ONGC - Drilling Operation Practices Manual.-2007

DRILLING OPERATION PRACTICES MANUAL

OIL AND NATURAL GAS CORPORATION LIMITED INSTITUTE OF DRILLING TECHNOLOGY DEHRADUN, INDIA

FOR INTERNAL CIRCULATION ONLY

First Edition January 2007

Published by V.K.Jain Head-IDT Institute of Drilling Technology Oil and Natural Gas Corporation Ltd. Kaulagarh Road, Dehradun-248195, INDIA

Preparation Team A.B.Sharma Rajeev Dhupar R.P.Patel D.Das Gupta A.K.Joshi Ram Shanker

Designed & Printed by Shiva Offset Press, Dehradun 14, Old Connaught Place Dehradun Ph.: 0135-2715748; Fax : 0135-2715107, E-mail : [email protected]

rsy ,oa izkÑfrd xSl vk;ksx fyfeVsM OIL AND NATURAL GAS CORPORATION LIMITED

TEL BHAVAN DEHRADUN-248003 0135-2754203 / 275 7753

R.S.SHARMA CHAIRMAN AND MANAGING DIRECTOR

MESSAGE Drilling of oil and gas wells is a very complex operation requiring application of latest technology, accurate procedures of different activities of drilling operation and total attention is required for successful completion of the well. A healthy well is a requirement for optimum production of hydrocarbons. It is a matter of great happiness that Institute of Drilling Technology has prepared a Drilling Operation Practices Manual to provide assistance to the field engineers engaged in drilling a well including application of Drilling Fluid Engineering and Cementation Technology. I am sure that this manual will help to update the technological knowledge of drilling engineers, cementing engineers, mud engineers and other technical staff in field applications. In addition, it would also be of help to other disciplines associated with drilling and completion of wells.

R.S.SHARMA

rsy ,oa izkÑfrd xSl vk;ksx fyfeVsM OIL AND NATURAL GAS CORPORATION LIMITED

TEL BHAVAN DEHRADUN-248003 Phone 0135-2753372 Fax: 0135-2753524 Telex: 0585-206/207

U.N.BOSE Director (Technology & Field Services)

FOREWORD I am happy that earnest efforts have been made by Institute of Drilling Technology to bring out a Drilling Operation Practices Manual for ready reference by the field personnel. I am sure that the manual will be of immense use in providing necessary procedures & guidelines for carrying out operations correctly and efficiently on drilling rigs. Drilling Operation Practices Manual assumes a great importance particularly in view of the fact that drilling activity has been growing rapidly in volume and has also become more complex during the last few years. These complexities need immediate solution for which the Drilling Operation Practices manual would serve as a ready reference in field applications. This will also go a long way in streamlining the procedures being followed for various operations while drilling wells both onshore and offshore. I wish every field person should go through the manual thoroughly to implement the guidelines and procedures contained therein for performing drilling operations in the most efficient and cost effective manner. My best wishes

U.N.BOSE

PREFACE In the fast changing scenario worldwide in the field of drilling technology, publication of a DRILLING OPERATION PRACTICES MANUAL was felt necessary so that our executives on the rig can follow uniform Practices & Procedures and thereby increase the efficiency & productivity of drilling operations. This manual has also been attempted with an aim to collect all scattered mateials required for drilling engineers at one place. Thus, in a single reference book their need may be satisfied to the great extent. The book provides adequate theoretical, practical background explanation before setting operations procedures/guidelines in order to enable the users understand the procedures behind practices. The manual has also been specially designed with the objective of providing an insight to various operations and procedures carried out right from release of a drilling location to completion of drilling and testing of a well. Therefore, it will be an extremely useful reference handbook to the drilling engineers, mud engineers and cementing engineers especially to the new entrants in this field, for performing their assignment. The topics are devised in a way that should give a good basic understanding of the subject at all levels. Also, the topics discussed in this manual will play significant role in proper well planning, execution, monitoring and solving down hole complications. Proper and healthy use of this manual is bound to develop good understanding and better co-ordination among the interdisciplinary groups thereby creating an environment of synergy. A Team of highly qualified and experienced young executives has prepared this manual and it has been edited by very senior knowledgeable executives. Apart from our in-house publications, useful materials from the publications of various companies/authors/publishers have been used in this manual for maintaining its quality. Suggestions received from various quarters, at different stages of finalization of this manual, were examined critically and incorporated in the manual wherever possible. I am confident that humble effort of brining out this manual will benefit all the concerned users in playing a healthy role in the organization in addition to develop technical capabilities of individual.

V.K.JAIN Head - IDT

ACKNOWLEDGEMENT I would specially thank the C&MD and all the Directors of the Corporation for giving us the opportunity for preparing the Drilling Operation Practices manual. A work of this nature could not have taken shape without their constant interest, support and encouragement. Inspite of pressing operational requirements, they could spare their time and resources in bringing out this manual. Special thanks are reserved for Late Sh. A.T.Kali, EX-CDS for his constant association and valuable suggestions in giving shape to this manual. I would like to thank S/Sh M.D.Joshi, ED-CDS; A.K.Vig, GGM(D) OVL; V.I.Methew, GGM(D), HDS, Sibsagar and other senior executives of Drilling Services for giving valuable suggestions to improve the quality of the manual. Again, I would like to thank Sh. Ram Shanker, Chief Engineer (D), who remained the key person during compilation, editing and printing the manual, whose sincere efforts made the publication of this manual possible. I would like to thank S/Sh K.M. Bhattacharya, DGM(D), HDS-Frontier Basin; Dr. Vinod Sharma, DGM (Chem),I/C DFE; Dr. D. Bandhopadhyay, DGM (Chem), I/C-R&D; S.K.Dobhal, Head-DTS; D. Pramanik, Head-WCS; R.P.Patel, CE(D); A.Javed, C.E.(D), Head Monitoring Group; Rajeev Dhupar, CE(D), Head-R&D; D. Dasgupta, CE(D), Head-CCM; A. Dutta, C.E.(D), Head-TSG as well as all the officers and staff of IDT who extended their co-operation in preparation of this manual. I would like to thank Shri A.B.Sharma, DGM(D), I/C-Training; who remained the key person during editing and printing of the manual. I would like to thank the authors of all 20 chapters i.e. S/Sh S.K. Dobhal, A.K. Joshi, Vishwajeet Das, Ram Shanker, A.Dutta, V. Chakraborty, Vinod Kumar, Anurag Ahuja, TRK Sherwani, Ajeeth Xavier Parapullil, A.K. Saxena, P.K.Dubey, P.S. Sehmi, Sanjay Kulkarni, A. Bhattacharjee, G. Venkesteshwaran, R.P. Agarwal, A.N.Singh, S. Bhattacharjee, A.K. Dwivedi as well as all the officers and staff of IDT who spared their time in writing the subject procedures and bringing out this manual in addition to their other assignments. My sincere thanks to the authors, companies and publishers who have permitted us to use their publication materials in our manual as well as whose materials have been referred to during preparation of this manual. The following persons deserve mention of their active association in preparation of this manual in different capacities: S/Sh A.K.Mishra, DGM (D) Mumbai; R. Manimmanan, Supdtg. Librarian now in IPSHEM Goa.

The following companies/authors/publishers are being acknowledged thanks for permitting reproduction of their material for this manual. M/S. API Smith International, Security Dresser Industries Inc., Petroleum Extention Services Division, Pannwell Publishing Company, Gulf Publishing Company (World Oil), Dowell Schlumberger Inc., M/S Hycalog, M/S Sperry-sun Drilling Services, M/S Schlumberger Asia Services Ltd., M/S Hughes Christensen Company, Society of Petroleum Engineers (USA). Finally, I acknowledge the services rendered by M/S Shiva Offset Press in bringing out the manual in this form.

V.K.Jain

CONTENTS S.NO

SUBJECT

........

PAGE

1

LAND RIG CLASSIFICATION AND RIG BUILDING

........

1

2

OFFSHORE RIG

........

22

3

DRILLING OPERATIONS

........

36

4

HYDRAULICS

........

47

5

DRILLING BIT

........

51

6

WELL LOGGING

........

54

7

BHA SELECTION

........

59

8

DRILL STRING

........

65

9

WIRE ROPE

........

71

10

WELL HEAD FITTING

........

85

11

BOP STACK

........

96

12

WELL CONTROL

........

116

13

DOWN HOLE COMPLICATIONS

........

141

14

CASING OPERATIONS

........

177

15

DRILL STEM TESTING

........

189

16

CORING OPERATION

........

196

17

DIRECTIONAL DRILLING

........

205

18

CEMENTING OPERATIONS

........

219

19

DRILLING FLUID

........

245

20

EMERGING TECHNOLOGIES

........

276

21

REFERENCES

........

355

Land Rig Classification and Rig Building

CHAPTER – 1

LAND RIG CLASSIFICATION AND RIG BUILDING Based on the type of rig, the drill site for the future well must be prepared for proper placement of equipment. The land around the well site is cleared, graded & leveled. A cellar pit is made along with rig specific foundation. For all other auxiliary equipment placement leveled foundation strips are made. If necessary, local roads and appropriate areas around the rig are surfaced to facilitate transportation of rig equipments. Drilling rig equipment can be divided in 2 systems: 1. Mast and sub-structure 2. Power system a) A.C. –D.C. b) D.C.-D.C. (obsolete now) Most land rigs come under two categories (a) Carrier-mounted Rigs These are also called mobile rigs. In which rig is mounted on wheeled carrier. This carrier can be driven to the well site with all necessary hoisting equipment, engines and special telescopic mast as complete on truck unit. These rigs are for shallower depth wells. (b) High Floor Mast & Sub Structure These are higher capacity rigs. In this rig components are transported to new location with the help of trucks and heavy-duty trailers. High Floor Mast & Sub structure rigs in ONGC are • •

BHEL Electrical Rig Romanian Electrical Rig

Type of Rigs

Capacity (ft.)

Shallow

Medium

Deeper

Super Deep

Type - I

Type - II

Type - III

Super Deep

16000

20000

12000

20000-30000

Draw works(HP)

≤1000

1400/1500

2000

3000

Rig HP(Power Pack)

3000

4000

4000

6000

Mechanical Drive System

IR-750 IR-900 IPS-700 BHEL-450

Electrical Drive System

E-760 F-3050 MBHEL-760

E-1400 F-4900 BI-1500

E-2000 F-6100 ARMCO-1320UEBI-2000

E-3000

1

Drilling Operation Practices Manual

1.1 BHEL Electrical Rigs are of two types (i) Sky Top / Brewster design – High floor modular Rig: This design is an improved modular rig having elevatable drill floor, coupled to a low structure, through parallel spaced links. The base of mast is pivotally supported from the derrick floor, rather than base. Various elevating systems are provided for raising the derrick floors through line and sheave arrangement. Steps involved in raising of sky top type rig: 1. Rear floor raising along with draw-works 2. Front Floor raising 3. Spreading of A-frame and Mast erection (ii) Branham Industries Universal Cantilever Swing lift (Type1) mast: This design is an improved version having self-elevating sub-structure. Draw-works and surrounding floor are raised to drilling position by use of draw-works power and mast raising line, no other rigging or wire line required. Mast raising lines need only be moved from A-frame sheaves to the sheaves on draw-works elevator to complete rigging for erection. Steps involved in raising of Branham type rig: 1. A-frame erection & Raising of Mast with set back parallelogram in place 2. Raising of rear floor with draw-works. 1.1.1 Rig Components of BHEL Electrical Rig Sub-Bases (Bottom Boxes): The sub-base assembly is designed to transmit the various loads to infirm soil conditions. Box type substructure consists of a pair of separated yet parallel rectangular boxes connected by pinned beam having provisions for mounting of / substructure and supporting drilling equipment. Sub-Structure: It takes over mast, rotary table, draw works and other loads generated during drilling operation and transmit them to sub base. It also resists forces during raising and lowering of front and rear floors and also loads during mast raising and lowering. It is also designed to resist the loads coming in addition to above due to storage of drill pipes, drill collars and casings. It consists of a structured framing system of trusses, beams and girders connected to columns. Mast-A Frame: - Acts as gin pole and provide high leverage to the bull line for mast raising operation. This takes entire mast load from slings through the pulleys provided and transmits it to the ground through sub-base. In normal operating condition it supports the sub structure and transmits the loads from mast to the sub base. Designed with wide flange beams, this is subjected to heavy torsional loads. Mast: - The mast is freestanding cantilever with rectangular shaped cross-section providing ample clearance for traveling block and also to facilitate easy handling of drill pipes. It is assembled by joining five parts in sky top design or by joining six parts in branham design. Racking Platform: To accommodate drill pipes during tripping. 1.2 RIG MOVE/ BUILDING PROCEDURE Rig building operations involves the following activities A. Drill site preparation 2


B. C. D. E.

Route survey Rig release / Rigging Down Transportation of rig equipments Rigging Up

Above mentioned first two activities are performed before actual rig release from old location. A. Drill Site Preparation: (Before rig release) a. All statutory and regulatory clearances should be obtained wherever it is necessary b. During stacking of site, it should be seen that no overhead electrical line passes through drill site area (at least 30 mts. away from well mouth). c. Site area should be inspected and ensured that its layout is suitable for the type of rig to be deployed there. d. Approach road should preferably be in line with the centerline of the well for giving enough space for vehicle movement. e. Rig foundation should be as per the rig specifications and designed based on bearing capacity of soil. f. Surrounding area of all equipment foundation should be hardened to bear the load of heavy transport vehicles. g. Foundation level should be maintained for sub base structure and for the auxiliary equipments like PCRs, Power pack, Mud pumps. h. If concrete slabs are used as foundation for auxiliary equipment, then all the slabs should be at the same level and ground should be strong enough to support the load. i. Concrete slabs for mud tanks should be strong enough to support the load of completely filled tanks. j. Anchors for top man escape device, out line, BOP etc. should be grouted properly. k. Proper drainage for entire rig site to be provided. l. Effluent pit, Cutting pit, Waste pit and Oil pit should be as per the requirement of OISD standard. m. Entire drill site area should be fenced with barbed wire and there should be only one entry point. n. In cluster drilling site, all flow lines of the previous wells should be buried underground and X-mass tree of old well should be caged. o. Diesel tank should be enclosed to arrest HSD spillage. p. Security personnel be posted at new location before transportation. B. Route Survey: (Before rig release) Route survey shall be conducted prior to rig shifting and following points should be taken into consideration with respect to the type of rig to be transported: a. Width and strength of the road. b. Strength of bridges and culverts. c. Height of the electrical transmission lines. d. Railway crossing and traction lines. e. Radius of curvature on turnings. 3


f. Obstruction due to trees / branches. g. Crossing points availability / requirement. h. Traffic in the cities en-route at peak hours. In case, if any problem related to above aspects is noticed, then it should be rectified before start of rig shifting. Route survey team should consist of: z Rig In-charge z Electrical Engineer z Civil Engineer z Logistics personnel z Land acquisition man C. Rig release/Rigging down After releasing the rig from existing location the following procedure should be ensured. a. Derrick floor should be free of all unwanted materials prior to lowering of mast. b. Flow line of the existing well or cluster well, if any should be protected from any inadvertent damage. c. It should be ensured that safety clips of every pin are in place. d. Rotary hoses should be secured and dismantle H-manifold and other pipes. e. It should be ensured that there is no loose item on mast members. f. Mast raising and lowering sheaves and their guards should be inspected. g. Mast raising and lowering lines (bull lines) should be inspected for any damage. h. Tackle system should be checked for free rotation of pulleys. i. Proper functioning of the clutches, brakes, weight indicator and quick release valve should be checked. j. Ensure that mast-snubbing system is functioning properly if available. k. In case of non-availability of mast snubbing system, ensure that the snub line is of sufficient length and without any joint. l. It should be ensured that the racking board, stabbing board, railings, fingers of monkey board etc. is folded wherever applicable. Fold diving board of monkey board. m. All long hanging lines, cat lines, and sand lines should be tied up to the mast. n. Ensure that bottom boxes (rear and front extensions) wherever applicable are properly fitted and bolted. o. Fill water in bottom boxes wherever applicable. p. Ensure the correct positioning of horse so that monkey board should not touch ground. q. The front area of mast should be cleared for movement of chain tractor / Mole trailer. r. Properly reeve bull lines for lowering of mast. s. Ensure that all un-wanted persons are away during mast lowering from rig floor. t. Mast should be lowered at slowest possible speed. Application of brakes at any stage should not create any jerk. During lowering check the rotation of the pulleys, and if any abnormality is observed, operations should be stopped for taking corrective action. u. A designated experienced person who knows the procedures should lower the mast. v. Raising and lowering of mast should be done in daylight. 4


w. Rest the mast on horse and remove monkey board, belly board, BOP trolley beams etc. x. As far as possible, brake shoes shall not be replaced prior to lowering and raising of mast. If it becomes necessary to replace the shoes, ensure proper break-in. D. Load Handling and Transportation Rig equipment dimensional details, weight with regard to transportation should be well documented. Loads should be assigned to transport fleet sequentially. (Annexure-1) a. Proper transport fleet should be chosen based on equipment dimensions and weight and route selected, especially in hilly area. b. Fitness certificates of transport fleet should be checked before commencing shifting. c. Ensure proper rating of truck, crane before handling any load. d. Crane jacks should not be placed on auxiliary equipment foundation. e. Planks / concrete slabs should be provided below the crane jacks based on the weight of the equipment to be lifted and soil condition. f. Hooks for lifting should be engaged only on lifting lugs/eyes provided on the equipment being lifted. g. Lifter beams for lifting the equipment like PCR house, power packs, diesel tanks etc. should be used. h. Unwanted person should not be allowed in the vicinity of the lifted load. Tug lines should be used for handling loads while lifting / placing. i. Damaged or kinked or twisted slings should not be used for lifting of loads. j. On trailers load should be properly secured with proper chains/ropes during transportation. k. The equipment with liquid inside the tanks e.g. mud, diesel etc. should not be lifted / transported. l. No loose material should be stored inside the PCR, engine room, compressor shed, etc. m. Minimum clearance from overhead lines to the transporting equipment shall be maintained. In case minimum clearance required is not met, then power lines shall be de-energized. E. Rigging Up a. Ensure all equipment reaches at new location in good working condition. b. Align sub-base structure to the center of the well. Assemble the sub-structure and assemble the mast. c. Check and service mast-lifting sheaves and equalizer pulley. d. Check mast bull lines for broken wires, corrosion, incidental damage etc. (Refer Annex-2) e. Fix the casing line guide roller on the mast wherever it is applicable. f. Check reeving of bull lines. g. Reeve the traveling block, fix fast end, spool the casing line on drum and tighten the dead end properly. h. Check functioning of clutch, brake and ECB. i. Check mast members for cracks and bends etc while fitting. j. Grease all the pins before fitting and fit all the safety clips in all pin.

5


k. Unwanted lines like tong hanging lines, cat lines etc. should be tied to the side of the mast to avoid entangling during lifting of mast. l. Ensure bottom boxes and sub base extensions are fitted properly. Fill water in bottom boxes (wherever applicable). m. At least two power packs should be available during rig building. n. Check the condition of bumper blocks (wooden blocks) and its clamps at crown block. o. Lift the mast from the horse saddle about 6 inches and hold it there for 5 minutes and observe for: z Any cracks on foundation. z Leakage of air/oil. z Any other abnormality If any abnormality observed take corrective actions. p. Raise the mast with slowest possible speed. q. Observe the lifting mechanism sheaves for any hindrance in rotation, and load on weight indicator. r. Observe casing line of tackle system for any obstruction with monkey board while lifting of mast. s. During the final stage of mast raising bull lines lose its tension due to fall of the mast towards A-frame. So the fall back of the mast should be controlled with the help of hydraulic snubbing system or snubbing line. t. Align the mast with A-frame pinholes, fix the proper size pins and then release the snub line. 1.3 RIG UP PROCEDURES (A) Sky Top Mast (1) Steps Involved The assembly of rig comprises following steps: - (Fig.1-sky top mast) z Assemble sub-base on ground adjacent to well site 26,28,30. z Erection of strong back on sub-base 34,36. z Connection of rear and front support floor to the base by means of parallel spaced leg 18,24. z Fixing of draw-works with the rear floor. z Couple the mast lower end to the front floors. z Raise the rear floor along with draw works. (Fig. 2) z Raising of front Floor (Fig. 4) and erection of mast. (2) Procedures for Assembling: a) Sub-base a. Place and align middle sub-base sections of DS (Driller side) and ODS (Off Driller side), with respect to center of well. Connect spreader beams & braces. b. Connect and align rear sub-base boxes to the middle sub-base. Connect spreader beams & braces.

6


c. Connect front sub-base extensions to middle boxes while raising and lowering of mast only. NOTE: Front sub-base extensions may be removed for ease of operation. b) Sub-structure a. Install strong back columns and braces on sub-base in DS and ODS respectively and connect strong back spreader beam.

32

22

38

34

24

40

36

40

28

20

14

12

16

31 26

42

30

42

18

12a

12b

12c

12d

12e

10

Fig. 1 : 12-Mast (a, b, c, d, & e are mast section), 14-trailer, 16-Mast pivot, 18-Front support, 22-draw works Floor , 24-D/works support floor, 26-sub-base, 28-Rear halve of sub base, 30-Front halve of subbase, 31-sub-bases joining point , 32- Strong back Assembly, 34-vertical column of strong back assembly, 36-Digonal support to strong back assembly, 38-Sheave, 40-D/works support floor under structure, 42Front floor support under structure 38 104

106 22

104

116

12

88

26

18

32

112 108

110

26

80

Fig. 2 : 80-sheave, 88-Sheave, 104-casing line, 108-T/block hook, 110-direction of block movement, 112Rear floor raising bull line, 116-Rear floor raising line dead end

7


STRONGBACK COLUMN SHEAVES

TO CROWN

BLOCK

FRONT FLOOR SHEAVES BREAK OVER SHEAVES

STRONG BACK BEAM SHEAVES

EQUALIZER SHEAVES SB 26A MALE SOCKET FEMALE SOCKET

STRONG BACK COLUMN SHEAVES

SB 26B BREAK OVER SHEAVES FRONT FLOOR SHEAVES

Fig. 3: Rear Floor Reeving Diagram

38 106 22

104 120

12

88

24

32

18

114 118

108

110

26

Fig.4: 120-Front floor raising bull line dead end

b c. d. e. f.

g.

Install columns of rear floor (DS & ODS) in horizontal position and connect rear floor boxes to it and connect draw-works spreaders. Position the draw-works on draw-works spreaders. Install front floor columns (DS & ODS) in horizontal position and connect their boxes to it and then connect spreaders. Place rotary table on rotary beams. Connect mast bottom section with front floor boxes and assemble other sections of mast, crown block. Connect ladders, electric fittings and ton-mile transmitter to the mast, but do not connect crown safety platform, racking platform and Belly board till front floor is raised. Keep the travelling block on Dolly board and reeve the casing line. 8


h. Rear floor raising Reeve rear floor raising lines and fast line (d/works) as per Fig. 3 and fix dead end connections on both sides. Raise the rear floor along with draw-works with the self-power of draw-works. i. Connect rear support box to strong back columns and fit the braces of rear floor boxes (DS & ODS). Connect all other joints with strong back beam. j. The mast is rested on trailer as per drawing for front floor raising (fig.1). k. Front floor raising Reeve front floor raising lines as per Fig. 5 and fix dead end connections on both side. Raise the front floor with the self-power of draw-works. The trailer must be allowed to follow the motion of mast. l. After front floor being elevated connect front floor support boxes to strong back. Also connect rotary spreader to strong back beam. m. Pin column braces of front floor (DS & ODS). n. Ensure all pins are well fitted and all member connections are perfect. o. Reeving for raising the floor Rear floor erection or lowering. z Use the rear floor raising line only, when front floor is down. z Use the front floor raising line only, when front floor is up. Front floor erection or lowering. z Use front floor raising line only, in all conditions.

STRONG BACK SHEAVES

TO CROWN

BLOCK

DEAD END CONN FRONT FLOOR SHEAVES STRONG BACK BEAM SHEAVES

BREAK OVER SHEAVES SB 26C

STRONG BACK SHEAVES

MALE SOCKET FEMALE SOCKET

DEAD END CONN

SB 26D FRONT FLOOR SHEAVES

BREAK OVER SHEAVES

Fig. 5 : Front Floor reeving diagram

Mast Erection a. Assemble (or expand if already fitted on mast) A-frame and swing its rear legs, fit it to the pedestal in rear floor boxes. b. Place the mast on the horse. c. Fix Belly Board, Racking platform (monkey board) and Crown block safety platform with handrails and other accessories. 9


d. Reeve bull lines as per Fig. 12 6. e. After raising floors pull Travelling Block and Dolly to within 40’-0" approximately 66 from the center of well. Use crane to lift traveling block to 60 the required height, pass bull line through equalizer 20 pulley and connect their ends. Then tighten casing 64 line for keeping Traveling Block in elevated position. 22 62 f. Racking finger and diving board should be secured to 16 hand railings of monkey 24 18 54 board. g. Attach necessary snub-line (in crown block) to protect the fallback of mast. 58 40 h. Slowly raise the mast till it 52 42 44 36 is near to vertical. Here bull 48 32 line will be slackened, so 40 control the mast fall back 42 with snub line. As the mast 34 56 26 pinholes align with A-frame holes, pin up mast to Aframe. i. Now bull line can be removed. Fig. 6 j. Center the mast before drilling, by an 8" drill collar hung from T/ block as a plumb. If required provide adequate shims for centering. (i) Jacking and lowering shall be done on one leg at a time. (ii) No bolts shall be removed from shoes, loosen nuts only. After alignments, tighten the nuts. Note: Remove front sub-base extension before start of drilling operations. k. Install all sub-structure accessories, such as adjustable flight stairway, exterior flooring, B.O.P. trolley beams Ramp and stair combination, handrails etc. (3) Procedure For Rigging Down Mast Lowering : - (Fig. 7) a. Attach front sub-base extension before lowering the mast. 10


b. Remove all sub-structure accessories and items added after erection of mast, which might interfere with lowering of mast. c. Reeve Bull line and attach snub line for initial motion of mast. d. Do not allow any slack on Bull line or fast line before and while lowering the mast. e. Guide floating sheave (in Aframe) to align with fast line during lowering. f. Place mast on horse.

600 LBs

00 86 s LB

C.G. 137600 Lbs 73’-3”

VIEW A-A

Floors Lowering (either the front or rear floor can be lowered first). a. Remove interior and exterior flooring and doghouse. APPROX 170’ - 0” TO 200’ b. Remove crown block safety platform, monkey board, and Fig. 7 Belly Board then place mast on small stand. c. Disengage bull lines and place T/block on dolly board. d. Rest mast top section on trailer. e. Reeve floor raising line as per the requirement of floor (Prefer front floor. Swing A-frame on mast). f. Whichever floor is lowered, first remove its column braces, box pins and spreader pins. g. Lower floor cautiously and trailer must be allowed to follow the mast forward movement. CAUTIONS (i) No floor raising line slack shall be allowed before or during lowering. (ii) Do not remove any braces or pins of the floor that is not ready for lowering. (B) Branham Mast Sequence one (Fig. 8) (i) Bottom Boxes, Spreaders, Braces and ‘A’ Frames a. Place DS and ODS Bottom Boxes on Center Line using Front and Rear Spreaders and Braces to ensure that the Bottom Boxes are correctly positioned. b. Pin and Bolt Front Extensions & Rear Extensions to Bottom Boxes. c. The A-Frames are normally transported folded into the Bottom Boxes. Erect A-frame on sub-base or bottom box. 11


C

A B

D Sequence one “A” Frame Erection

Fig. 8

d. The Draw-works Support Braces are normally transported pinned to Bottom Boxes. Sequence Two (Fig. 8) (ii) Setback, Mast, Crown, Ladders & Tong Counterweights a. Position Front Setback Legs on Support Arms on Bottom Box Extensions and Pin to Bottom Boxes of DS and ODS. b. Position Setback Spreader on Bottom Box Extension Stools, and pin to Front Setback Legs. Ensure that the top and bottom Setback Leg Pin connections are well greased. c. Pin Front B.O.P. Trolley Beam to Setback Spreader of DS and ODS. d. Pin Mast Bottom sections to Bottom Boxes and Pin to Setback Spreader of DS and ODS. Ensure that the Top and Bottom Pin connections are well greased. e. Pin Mast stub section Spreader to stub sections after mounting Fast-line Roller on the two pillow blocks supplied. Check free rotation of roller. f. Place Traveling Block, Hook and equalizer, with Hook approximately 60 ft. from centerline of Well. g. Assemble Mast lower sections of DS and ODS to lower section Spreader, lift section and pin to stub section and pin in lower section Braces. h. Place Mast assembly stands (small stand) under lower sections near the top and pack up as necessary. i. Assemble Mast middle sections of DS and ODS and middle section spreader. Lift section, pin to lower section, lift slightly to release Mast assembly stands, move stands to the front of middle section Braces. j. Attach lines to Tong Buckets and take lines through to the Brackets on the middle section, reeve snatch Block and tie line off at a convenient point on Stub Section. 12


k. Assemble Mast upper section of DS and ODS, lift section and pin to middle section, lift slightly to release mast assembly stand and move stand to front of upper section. l. Normally the Mast top section is transported with the Crown block attached. Lift Crown block with top section and pin to upper section. m. Assemble flooring extension, Braces and handrails to Crown Frame. Fit Core line Sheave, etc., to Crown Frame. n. Fit ladders to DS from Stub Section to Crown. o. Fit Standpipe. Clamps attached with ‘U’ Bolts to the lower and Stub Section of the Mast of ODS. Check that the Standpipe does not interfere with Setback Spreader when raising the Mast. If interference occurs remove Standpipe before Raising the Mast. p. Lift Mast at Crown with the Crown Pad eyes and place it on (16’0" high stand) horse under top Section near the Crown Frame. (iii) Drawworks etc. a. Pin rear draw works Support Columns to Bottom Boxes of DS and ODS and bolt together with Spreader. Grease pin connections. b. Pin Front draw works Support Column to Bottom Boxes of DS and ODS and bolt together with Spreader. Grease pin connections. c. Position draw works Support on Bottom Box and rear Extensions and pin to front and rear support columns. Grease pin connections. d. Pin draw works extension to draw works Support. e. Set draw works and bolt down as recommended by equipment Supplier. Connect air and Brake water systems, fill water tanks in bottom boxes of DS and ODS. f. Pin Rotary Support Beam Unit and Rotary Floor Support Units. g. Fit draw works flooring & Wing Flooring. (iv) Mast Reeving, Racking Board, Mast Raising and Snubbing (Place Traveling Block, Hook and Equalizer at approximately 60 ft. from the centerline of well before assembling the Mast Lower Section to the Mast Stub Section.) a. Before reeving, lubricate all Sheaves and ensure they rotate freely. Using the longest bull line connect open socket to bull line Anchor on Mast section and pass line over A-Frame Sheave, replace rear line guard roller, pass under vertical Sheave round horizontal Sheave on Stub section replacing both line guards then take bull line through equalizer (To fit bull line to equalizer it will be necessary to remove Sheave and shaft from the yoke). Place bull line between Side plates and then slide Sheave back into position replacing Shaft and securing bolt. Using shortest bull line connect open socket to bull line Anchor on Lower Section, then reeve as above connecting Open and Closed Socket together. Special care must be taken when uncoiling bull line, kink should not come in lines. b. Hook up weight indicator. c. Reeve casing line into tackle system with the help of wire rope, and fasten fast end to draw works drum. d. Place equalizer on Hook. 13


238∅ x 144’ SLING LINE (EIPS - IWRC)

r cho An e l g Sin

Single Line

“A” Frame ∅

“A” Frame

To Draw works

238 x 164’ SLING LINE (EIPS - IWRC)

Reeving Diagram For 142’ MAST

Fig. 9

e. Before Raising the Mast: z Check that the Bottom Section and Setback Legs pin connections are well greased. z Check that all bolts have been tightened. z Check that all pins have been fitted with Safety clips. z Check that all line guards have been fitted correctly. Check that all loose tools etc. have been removed from Mast and Crown. z Check that all the Line and bull line has been reeved correctly. f. Hook up BOP chain hoists of DS & ODS. g. Assemble monkey board and skid under Mast, lift the monkey board and pin it to Mast Middle sections at selected height for operating position. Pin support Brace to Mast middle section, swing and tie back Diving Board to handrails and open gates at Drill Collar fingers to the maximum. h. Connect Hydraulic Supply to ‘Quick connect’ Lines on A-Frames of DS and ODS. Test Cylinders to ensure that both Rams move simultaneously in the same direction. Fully extend Rams ready for Mast Snubbing. i. Lift the mast from the horse saddle about 6 inches and hold it there for 5 minutes and observe for: z Any cracks on foundation. z Leakage of air/oil. z Any other abnormality If any abnormality observed take corrective actions. j. Raise Mast slowly using draw works power until Mast touches Snubbing Noses of DS and ODS. Using the Control Unit retract Rams and Continue to Spool in slowly with draw works. During this operation the Mast will ‘Break over’ its center of gravity. Continue retracting 14


Fig. 10

Rams, while taking up slack with Hook until pin connections line up. Pin the mast with AFrame on both sides. (Fig. 10) k. Attach Ramp to Setback Support. Sequence Three (Fig. 11) (v) Drawworks Raising a. Remove rear Line Guard on A-Frame Sheaves, partly Lower Traveling Block, Change bull line DS and ODS from round to over top of A-Frame Sheave, using soft line from Catheads pull Loop in bull line behind A-Frame while continuing to lower Travelling Block, pass bull line over draw works Sheave of DS and ODS. Replace Line Guards and Take up Slack with Hook. 15

To Sin gle Lin eA nch or

To Block


SQUENCE THREE - REEVING OF DRAW WORKS

Fig. 11 b. Check that z Draw works Column Pins have been well greased z All Bolts have been tightened. z All pins have been fitted with Safety Clips. z All draw works and stub section line guards have been fitted. The A-Frame Line guards should not be fitted at this stage. Check that the bull line is reeved correctly. c. Slowly raise draw works with its power, ensure that the Rotary Beam connections line up and pin Rotary Beams to Setback Spreader. Pin all Rotary and Floor Beams to Setback and draw works. d. Swing up draw works Lock Brace of DS and ODS pin and fit Safety clips. e. Lower Traveling Block and remove bull line from draw works Sheaves of DS and ODS. Raise Travel Block and hang equalizer pulley and bull line in the Mast, remove from Hook. Or Lower to Drill Floor, remove and store Equalizer pulley and bull line. (vi) Doghouse Support and Misc. Items a. Hookups dog house support, drill floor panels and other miscellaneous items. b. Remove bottom box rear extensions and also remove bottom box front extension (DS) for entry of BOP stack. 16


c.

Center the mast before drilling, by an 8" drill collar hung from T/ block as a plumb. If required provide adequate shims for centering. (i) Jacking and lowering shall be done on one leg at a time. (ii) No bolts shall be removed from shoes, loosen nuts only. After alignment, tighten the nuts.

(vii) Lowering Sequence a. The Lowering Sequence is the reverse of the Raising Sequence. The main sequence is as below. b. Remove any additional items added after Erection, which might interfere with the Lowering procedure. c. Reverse Section F. d. IMPORTANT Remove rear B.O.P. Trolley Beams, Hoists and Trolleys. Re-hook Equalizer pulley with bull line, Reeve bull lines as Section E, making sure that the bull lines pass over the A-Frames Sheaves of DS and ODS, and round draw works Support Sheaves of DS and ODS and sockets are correctly pinned to Lower section Mast of DS and ODS. Replace Line Guards at Stub and draw works Sheaves. Tighten block and check Lines. e. Unpin and lower draw works Lock Brace. f. Unpin Rotary Beam Unit at draw works only. g. Unpin Rotary Floor Beams at Setback only. h. Cautiously lower the draw works. i. Connect Hydraulic’ Power to snubbing unit of DS and ODS. j. IMPORTANT Change Bull line of DS and ODS as shown on section D. Make sure the bull lines are round A-Frame Sheaves of DS and ODS. k. Replace Line Guards. l. Tighten block and recheck bull lines. m. To lower Mast remove pins and extend Rams of snubbing unit while lowering the Hook, maintaining very little slack as Mast ‘breaks over’ its Center of Gravity, continue to lower mast onto Mast horse. Continue section D to A in reverse order for further de-rigging. SLING (BULL) LINE INSPECTION AND REPLACEMENT There are three factors, which may limit the life of sling line. (1) Wear due to operation: it is a function of the number of times the mast is raised. (2) Corrosion: It is related to time and atmospheric conditions. (3) Incidental damage: It may occur at first location or any other location. Points to be kept in mind for inspection & replacement of sling lines: a. Data used for replacement does not give any clue. Because some times line are replaced early due to incidental damage and some times lines are used beyond the time when they should be replaced. b. There is no way of judging the remaining strength of a rusty rope, so it should be replaced. Especially areas adjacent to end connections should be examined closely for any corrosion. In coastal areas sling lines left hanging in the mast may become corroded and found unfit for further use. 17


c.

d. e.

It is possible to establish sling line life expectancy in terms of number of locations on which it was used, as long as a set number of months were not exceeded. But again this will not preclude the necessity of careful inspection. A line showing with broken wires should be replaced. A line with any material reduction of metal from abrasion should be replaced. A line showing kinking, crushing, or any other damage resulting in distortion of rope structure should be replaced. Replacement of lines based on normal life expectancy will provide some degree of safety, but due to which there should not be any laxity in sling line inspection. Sling line should be maintained in a well-lubricated condition. The field lubricant should be compatible with the original lubricant. The object of rope lubrication is to reduce internal friction and prevent corrosion.

18


Annexure-1 RIG BUILDING PLAN BHEL Electrical Rig / Sky Top/ Brahnam : Day wise activities and requirement of fleet: Job to be done

Crane

D1

Cleaning front side of mast, dismantling of mud system/mud pumps, two power packs, and one diesel tank/water tank/hopper.Loads: Power pack – 2 Diesel tank – 1 Water tank – 3 Water tank Skid –1 Hoppers skid – 1 Reserve tank – 4 BOP Control – 1 Trip Tank -1

Type 1 (OS) Type 2 (OS) Type 2 (NS)

1 2 1

14

D2

Lowering of Mast, substructure, dismantling of mastTPT: Mud pumps – 2 Power Pack – 2 Diesel tank – 1 Utility (Compressor) house – 1 Mud tank –3 Super charger with skid – 1 Degas/D. silt. Pump – 1 Mast & structure – 4 Monkey Board – 1 Belly board - 1


1 2 2

17


1 2 2

14

Type 2 (OS) Type 1 (NS) Type 2 (NS)

2 1 2

9

D3

Dismantling of mast & substructureTPT: Mast section – 5 Set back – 1 Draw works – 1 Draw works platform – 1 Bottom Boxes – 2 Tubular – 2 Other loads like desander, desilter, Shale shaker - 1 T/Block etc. - 1

D4

Assembling of substructure and mast. Continue assembly of mud system TPT:Cat walk – 1 Dog House – 1 HP Line – 1 Mast & substructure left over items – 1 Mech./ Elect. Bunk Houses –2 Store Rooms - 3

19

Days

Trailer Load


Job to be done

D5

D6

Crane

Assembling of mast completed & casing line reeving and assembly of mud system. TPT: DIC Bunk house – 1 Staff Bunk House – 1 PCR – 2 BOP, Choke & Kill assembly and other left over Tubular -2 Lift mast on horse & fix Monkey Board, belly board. Mud system to be completed TPT: Complete transportation from old site

Days

Trailer Load


1 1 3

6


1 1 2

6

D7

Checking of power and raise the mast, fixing of d/floors, HP lines, removal of bull lines. Fitting of cat walk/ inclined ramp, pipe rack dog house.


1 1 2

D8

Preparation of spudding

Type 2(NS)

1

Abbreviations:- OS – Old site, NS – New Site, Note: 1. Rig movement is within the radius of 20 Km. during good weather condition. 2. Rig equipment should be transported on above priority so that it is unloaded at appropriate place at new site. 3. For sky top mast one more day is required due to its design. 4. Type 1 crane capacity – 75 Ton , Type 2 crane capacity – 30-40 Ton 5. Also 1 Truck is needed for miscellaneous items as per the requirement of rig In-charge.

20


Annexure-2 SIZES OF DIFFERENT LIFTING LINES SKY TOP MAST SN

Type of Rig

Type of Line

Description

1.

E -760

Bull Line

(i)

Floor Lifting Line

(ii)

(iii)

(iv) (v) 2.

E-2000

Bull Line

(i)

Floor Lifting Line

(ii) (iii) (iv) (v)

Snub Line

Remarks

1 ¾” Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 127’-6" 1 ¾” Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 147’-6" 1 1/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 142’ 1 1/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 163’ 1 1/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 90’ 2" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 126’ 2" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 150’ 1 1/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 142’ 1 1/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 163’ 1 1/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS, RHRL 90’ ½” Φ, 6 × 37 classification, 6x49 construction, IWRC, EIPS,

Both Open end

One open end & One closed end One open end & One closed end

Both open end Both open end Both open end One open end & One closed end One open end & One closed end Both open end Both open end

For Front Floor Use – (iii) + (v) For Rear Floor Use – (iii) + (iv)

BRANHAM MAST SN

Type of rig

Type of Line

Description

Remarks

1.

E-760

Bull Line

2 3/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, IPS, RHRL, 145’ (ii) 2 3/8" Φ, 6 × 37 classification, 6 × 49 classification, IWRC, IPS, RHRL, 135’

One Open socket & One closed socket. Both Open end socket

2.

E-1400

Bull Line

2 3/8" Φ, 6 × construction, (ii) 2 3/8" Φ, 6 × construction,

37 classification, 6x49 IWRC, IPS, RHRL,164’ 37 classification, 6x49 IWRC, IPS, RHRL, 144’

One Open socket & One closed socket Both Open end socket

3.

E-2000

Bull Line

2 3/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, IPS, RHRL, 194’ (ii) 2 3/8" Φ, 6 × 37 classification, 6x49 construction, IWRC, IPS, RHRL, 175’

One Open socket & One closed socket Both Open end socket

(i)

(i)

(i)

21


CHAPTER- 2

OFFSHORE RIG Independent-leg units and mat-type units are designed to withstand certain operating limits for (1) load capacities (2) afloat conditions and (3) elevated conditions. Any attempt to exceed these limits will jeopardize the safety of the crew and the unit. Jacking and moving procedures must take into account the capabilities and limitations of the unit when sitting on bottom, when afloat, or under tow. All personnel operating the unit’s equipment should read the “Information and Operating Instruction Book” published by the manufacturer. This book gives specific instruction on the operation and maintenance of the unit’s machinery. Newly classed ABS jack up rigs have emergency power sources. Check the emergency power plant and all emergency systems at least once a week. Emergency repair supplies should be on board, and be inspected periodically for quantity and condition. 2.1 PERSON ON BOARD: Recommended Nos. & type of persons to jack down and move drilling units are: NUMBER

POSITION/LEVEL

TASK DESCRIPTION

1

Move Supervisor

In charge of operation

1

Tool pusher

Assigns individual responsibilities; is jacking console operator

1

Driller

Maintains proper clearances and communication with console operator

1

Rig Engineer

Assigns Electrician, Mechanic, and Motorman responsibilities and stands by to assist

1

Electrician

Stands by below deck to take action to correct any electrical malfunction

1

Mechanic

Stands by below deck to take action to correct any mechanical malfunction

1

Welder

Assures that welding equipment is in good condition and that welding supplies are on board

1

Derrick man

2

Motorman

6

Roughnecks or Roustabouts

Three men assigned to each yoke house

2.2 JACKING DOWN OPERATION 1. Switch fixed pins to “OUT” on all columns. 2. Lower yokes (raise platform) slightly with master jacking lever, monitoring rod end pressure gauges and “FIXED PIN OUT” light on all columns. If rod end pressure reaches 2500 psi on columns 1, 2, or 3 before the red “FIXED PIN OUT” light on any of those columns comes 22

Offshore Rig

on, stop jacking until the fixed pin (or pins) which may be stuck is disengaged. Confirmation of the pin situation from each column should be obtained with every pin change before proceeding with the jack-ing. This information should be obtained by telephone from personnel in each jack house. 3. When all fixed pins are confirmed to be “OUT,” use the master jacking lever to raise the yokes (lower the platform) in unison one full, six-foot stroke. During the stroke, the aluminum wedges can be removed. NOTE : The automatic leveling device incorporated within the jacking system should keep the three yokes in line to: 1 inch relative to column 1 during the power stroke. During the power stroke and when about 10 inches from the end of the stroke, switch all the fixed pins to the “IN” position on the console and continue jacking in the same direction. These pins will not move all the way in immediately as they are not centered over the respective pin holes, but the “FIXED PIN OUT” lights will go off and the pins will be loaded up against the columns ready to go into the column pin holes as soon as they become aligned. As the end of the stroke nears, watch both the “FIXED PIN IN” lights and the rod-end pressure gauges for all three columns. The green “FIXED PIN IN” lights, indicating that all fixed pins are in, should come on before rod end pressure starts to decrease. If there is an indication of pressure decrease before a green light activates on any one column, jacking should be stopped until the cause of the problem can be determined (such as a stuck fixed pin, a maladjusted limit switch, etc.). 4. When all fixed pins are “IN” and confirmed, switch yoke pins to “OUT” position on the console, and use the master jacking lever to raise the yokes (transfer the platform load to the fixed pins), allowing the yoke pins to disengage themselves from the columns. Confirm yoke pin disengagement and then push the master jacking lever to the “YOKES DOWN” position for the return stroke (six feet). Switch yoke pins back to the “IN” position, again, about six inches before the end of the return stroke, and continue jacking until all yoke pins are “IN” as before and confirmed. 5. Repeat steps 2, 3, and 4 as required to bring the platform down to the water. Before the platform enters the water, a platform weight summary and platform longitudinal center of gravity (LCG) calculations are to be made. This is required for determining the amount of drilling water to be shifted in the platform in order to obtain even keel conditions when the mat is free and the unit floating. The method for adjusting the platform LCG to coincide with the floating longitudinal center of buoyancy (LCB) will normally be by shifting drilling water only. If feasible for the particular drilling unit and location, the derrick skid unit may also be moved to expedite the adjusting of the LCG. Continue jacking down until platform draft exceeds the calculated floating draft by two feet. With this amount of excess buoyancy, the mat should free itself from the sea bottom, as can be observed by a decrease in platform draft and head end pressure on all three columns. If difficulty is encountered and the mat will not pull loose with two feet excess draft, provisions have been made for water to be jetted from the underside of the mat. The piping for this system terminates in column 1. 6. Using the same action it took to lower the platform, raise the mat the desired clearance (bottom to bottom) for the move. If it is desired to raise the mat up to the uppermost position (2’6" clearance between the molded platform bottom and mat deck), override the automatic shutdown at columns 2 and 3. This is accomplished by holding the override button down in the lower left corner of the console before the end of the last 4’6" stroke is reached. 23


7. When sufficient clearance between the bottom of the mat and sea bottom exists, pressure up the rod ends of all cylinders (lower the yokes) with both the fixed pins and the yoke pins engaged and the yoke down to about 1500 psi. This will prevent relative movement between mat and platform due to wave action. If after a period of time the pressure decreases in the rod end of the cylinders, they can be repressured to 1500 psi. GENERAL NOTES FOR SERVICE AFLOAT 1. All sounding tubes must be capped except, and only, when in actual use. 2. Manhole covers into the inner bottom tanks must be bolted closed at all times unless access to a tank is necessary. Immediately upon completion of each job requiring access to any tank, the manhole cover must again be bolted closed. 3. While the unit is afloat, all manifold valves and all bilge control valves in the tank piping systems must be closed unless, and only when, they are necessary for system operation. Also, all plugs, caps, etc., at filling points must be closed. 4. All watertight hatches, vents, and companionways must be secured watertight while the unit is afloat except when in actual use. 5. All watertight doors and thru-bulkhead vents are to be closed. 6. The preload dump valves must be closed at all times, both afloat and elevated, except during the actual discharge (dumping) of the preload. 2.3 RIG MOVE AND PRELOADING Preparation for drilling the next well should be carried out while the rig is moving between wells or locations. Rig movement and deck-loading conditions may determine the scope of work that can be carried out during rig move and positioning operations. 2.3.1 Procedure Conduct the shallow gas survey 1. Perform fluid end inspections on the mud pumps and change liners as specified in the well programme. 2. Reset relief valves (pop offs) of the mud pumps depending on the liner burst rating as required for the liner in use, settings are specified in the manufacturers recommendations (pressure test to be recorded on a chart). 3. Perform inspections of all BOP equipment e.g. BOPs, safety valves etc. If possible pressure test these items with water. 4. Service all standpipes, valves, chick sans, hoses, choke and kill manifold valves, and conduct pressure test of these if required. 5. Service / inspect all tensioning and BOP handling equipment e.g. conductor pipe or BOP tensioners. 6. All mud handling equipment should be serviced including, shale shakers, mud cleaner, desander, desilter and mud mixing equipment. The shale shakers should be fitted with the correct size of screen for the top-hole section as per requirement. 7. Check the calibration and function of all drilling instrumentation e.g. gauges, chart records. 24

Offshore Rig

2.3.2 Skid Cantilever and Rig Up Once the rig has been pre-loaded and jacked up to the final air gap, as per the operations manual, and permissions obtained from the OIM, drilling operations may commence. The first of which is to skid the cantilever and drilling package out to the desired operating position. During skidding operations position watchmen to ensure that the skid beams / package does not contact any of the installations/ fixed equipment. Service hoses, electrical loops and cable trays will also be monitored to prevent damage to them. 1. Once skidding of cantilever and drilling package is complete check that rotary table is positioned directly over the proposed well centre. . 2. Secure the cantilever and drilling package to prevent any movement during the well. 3. Install any drill floor access stairs, walkways and v-door ramp if removed for skidding. Install any safety equipment (handrails) and adjust / install mud return flow line. 2.4 SURFACE HOLE PREPARATION This phase of the process ensures that the rig is fully operational prior to the actual spudding of the well. It also verifies that all equipment and materials required for the surface hole section are on board, certified and in good working order. 2.4.1 Procedure 1. A Rig Specific Procedure for handling the Master Bushings during drilling, running surface casing, BOP and diverter operations be in place and followed. 2. When rigging up to run 30" and 20" casing, the bushings not be removed until the shoe joint is ready to be run through the rotary table. 3. A hole cover be in place when ongoing activities, associated with the removal and replacement of rotary table components, are suspended for any period of time. 4. A pre-spud meeting be held with all personnel involved in the operation. Minutes of these meetings be DOCUMENTED. 5. Ensure that all the relevant fishing equipments are available. 6. Consult with the Client and service personnel to verify the wellhead systems and stack up dimensions. 7. Specified quantities of mud chemicals, including barite and bentonite, should be on location. 8. Sufficient spud mud, with the correct properties as specified in the drilling programme, should be mixed ready for use. 9. Specified quantities of cement and additives should be on location. 10. Drilling consumables for the first hole sections should be on location including but not limited to wellheads, casing and its handling tools, drill bits and nozzles of various sizes stabilizers, hole openers and reamers. 11. All drilling tools supplied by the Client should be checked for compatibility with the Contractors equipment (e.g. correct tool joint connections). This should include both drilling and fishing tools. 12. Prepare the BHA, pick up, drift and rack enough drill pipe to complete the surface hole sections. Making up and racking stands during drilling operations is not permitted. 25


13. Measure the conductor pipe (measurements to be checked by clients representative) to determine the correct footage of hole to be drilled. 14. Check all conductor handling equipment for certification and compatibility with the size of casing to be run. 15. If casing is to be run using lifting eyes then check the slings shackles are available and are certified to the appropriate load rating. 16. Check that there is sufficient oxygen and acetylene equipment ready to cut the lifting eyes. 2.5 CONDUCTOR PILING (DRIVING) Conductor, drive pipe or structural pipe are all terms used to describe the first string of casing to be set. Sizes of casing vary depending on the Clients requirements and well plan. The casing size referred to in this section is 30" as it is the most common; however specific requirements will be issued in the well programmed. Initially it will allow a circulation system to be set up taking returns back to rig. It allows the diverter system to be hooked up. It also prevents surface sediments from sloughing and protects against rig foundation failure (washout). The 30" may be driven (hammered) from the seabed to a desired depth / refusal or to a pre-determined blow per foot count. 2.5.1 Procedures 1. Check the derrick, top drive, block, and crown prior to and after the hammering operations for any loose objects. 2. Paint the shoe joint white to assist with ROV observation. 3. Run the 30" casing to one joint above the seabed then rig up the hammer and chaser joint. 4. If available the ROV will observe seabed for obstructions prior to the 30" penetration. 5. All lifting gear on the hammer assembly will be checked for rating and certification. All shackles will be secured with split pins and checked periodically during the operation. 6. To ensure the 30" is vertical, tag the seabed and commence driving at slack tide. Record the rotary to seabed measurement and weight of 30" from rotary to seabed in the IADC drilling report. Once maximum bottom penetration is achieved from the weight of the 30" alone, allow the hammer and chaser joint to rest in the top of the 30". 7. Do not allow the hammer support slings to take load while driving, continue to watch them and slack off on the blocks simultaneously. 8. Ensure that hammer operator is also monitoring the support slings, is situated next to the controls and is able to stop the hammer blows should the need arise. 9. Do not set slips on the 30" once driving has commenced. 10. Should the desired shoe depth not be obtained before a pre-determined maximum blow count per foot of penetration or refusal, then it may be necessary to implement a drive / drill procedure. 2.5.2 Drive / drill procedure. 1. Rig down and layout the hammer then run in with a 26" bit and BHA. 2. Support the weight of the 30" while drilling using the conductor tensioning/support system. This may require the use of 30" elevators, pad eyes or a load ring on the 30". 3. While drilling limit the ROP to prevent overloading of the annulus and do not drill further than the shoe. 26

Offshore Rig

4. The 30" will not be driven if shallow gas is a potential problem unless the formations have been drilled and proven to be gas free. 2.6 FLOATERS Floaters are the drilling vessels that keep floating during the entire course of drilling and other operations. In off-shore, drilling is much economical with jack-up rigs but their limited water depth capability (generally 400 ft.) is a major handicap as we venture in deep waters. On the other hand, floaters, if equipped with dynamic positioning system are independent of water depth and seabed conditions. Also in the water depth range of jack-ups floaters also provide a solution to some problems like punch through locations. However, the initial investment and the operating cost of floaters are much higher than that of a jack-up rig. i)

Drillship Drill ships are suitable for water depths 20m-3000m plus. Drill ships are suitable for drilling in deeper waters beyond the limit of Jack-ups. Also, they can be deployed on a location where jack-up operations is not possible due to soft/loose seabed having a gradient more than the that required for Mat type jack-up. They are suited in logistically difficult areas as normally they have high load carrying capacities. However, anchor moored type ships are not suitable for harsh environments as their response to hydrodynamic forces is not as good as compared to Semis. Therefore in harsh weathers, downtime tends to be much more on a drill ship than a Semi. Otherwise, drill ships are more stable in terms of survival and station-keeping in adverse weather conditions as their CG is lower. The variable loads like casings, risers, tubulars, mud chemicals etc. are stored on a drill ship at much lower level as compared to a Semi. This keeps the CG at much lower level and imparts more stability to drillships. Drillships are normally cheaper than semi-submersibles for moderate environment areas. They can carry out exploratory drilling, development drilling on subsea templates and subsea completion of single wells.

ii) Semi-submersibles or Column Stabilised Rig These rigs are floater type rigs in which the drilling deck is mounted on columns which are supported by submerged pontoons or hulls. Around half the length of columns is also submerged in water. Semis can be triangular, rectangular or pentagonal type. The most popular is rectangular design in which there are two bottom hulls each supporting 3 to 4 columns on which working deck is placed. They are suitable for water depths from 30m - 2500m. They are more suitable in areas with rough sea conditions and harsh environ-ments including icy seas. They are designed to minimise the impact of hydrodynamic forces on the vessel thus greatly reducing the heave as well as roll and pitch. The pontoons are much below the surface of water and drilling deck is raised high up, keeping only the columns in contact with wave/ swell action. This way, its response to hydrodynamic forces is excellent. But they are more prone to capsizing as the centre of gravity keeps on moving up with the addition of load on top deck during drilling operations which is inevitable. This reduces meta- centric height and thus the righting lever & tendency to capsize increases. This results in a drastically reduced deck load capacity as compared to a drillship. Semis are costly in operations but are a better choice for areas where harsh weather prevails for a longer period during the year. 27


2.7 STATION KEEPING A. ANCHOR MOORED : 8, 9 or 10-point mooring, Self Propelled. Suitable for water depth upto 1500m. New ships are being designed which will be capable of anchor mooring in approx. 2400m of water depths. Turret moored rig are capable of reorienting themselves as per weather conditions using its turret and thrusters. B. DYNAMICALLY POSITIONED : Station keeping is done by DP system though anchors are also normally provided. They are self propelled and are suitable for areas with water depths greater than 1500m, or lower water depths with harsher environments or locations which may require quick movement like frequent storms, or places with subsea pipelines, communication lines etc. They are very costly to operate as fuel consumption is very high for DP system. 2.8 DIFFERENCE BETWEEN FLOATER AND JACK UP RIGS FLOATER

JACK-UP

Vessel keeps floating during the entire course of operations and is subjected to various movements like Roll, Pitch, Heave etc. which impede operations.

Once the vessel is jacked-up it stands firmly on the ocean floor like a fixed platform.

30" casing is lowered in a drilled 36" hole with seawater with no returns to the rig.

30" casing is piled in to the seabed.

26" hole is also drilled (generally) with seawater with no returns to the rig.

26" hole is drilled with seawater/mud and returns to rig.

Every casing string lowered in the well is terminated at the seabed (except liner casing).

Every casing string lowered in the well is brought up to the surface (except liner casing).

BOP stack (generally 18 ¾” bore) is lowered and installed at the seabed after 20" casing and once installed all the subsequent operations right up to abandoning of the well are carried through the stack .It has more functions and requires special handling system.

The BOP stack (generally 13 5/8") has to be removed for the installation of each section of well head. Dimensionally this stack is much smaller in size and has less no. of rams, annulars and Kill/chocke line valves.

A string of risers about 20" bore is used which needs a special tensioning system to maintain constant tension for heave compensation. .

A single riser pipe is used.

BOP control system is much more complex for remote operation and redundancy.

BOP control system is same as that is used on land rigs.

Drill String Motion Compensator is used to maintain WOB

Not required

28

Offshore Rig

2.9 SEQUENCE OF DRILLING A WELL FROM A FLOATER: • Once a location is released for the deployment of a floater, the site is surveyed and a marker buoy is dropped by the survey boat on the location for easy identification (In shallow water depth). • The vessel moves to the new location. • The vessel moves into position and the heading is adjusted depending on the prevailing sea condition. • The running of anchors begin with the help of anchor handling vessel. The anchors are laid as per a predetermined pattern, pre-tensioned and then slacked-off to the operating tension values. or • If the vessel is equipped with dynamic positioning system, the same is switched on to move into the position. • Final adjustment of heading and position is now made with the help of instrumentation. • The vessel is now ready to spud the well. • A temporary guide base is lowered to the seabed during the low tide with the help of guidelines. • The 36" hole is drilled 80 to 200 ft. below the mud line and 30" casing is run and cemented in place. During these operations there are no returns of circulating fluid to the rig. This casing is strictly for the structural support and will not sustain any pressures. A permanent guide frame is secured with 30" casing head while running casing to guide the BOP stack on the well head. • 26" hole is drilled for a 20" casing that is set about 1000 ft. below the mud line. Risers with a pin connector (without BOP stack) might be run with the diverter on top if shallow gas sands are likely to be encountered.. The diverter is required because the well can not be shut in on the 30" casing. In this case a pilot hole is drilled and then enlarged to 26" • 20" casing is run with 18 ¾” well head on top with a running tool and drill pipes. The casing is cemented in place • The 18 ¾” BOP stack is now run and latched on to the 18 ¾” well head. • The subsequent operations for drilling 13 3/8",9 5/8", 7" phases and the well testing are carried through the BOP stack • After testing, the well is often plugged and abandoned by squeezing cement into the perforations used for testing and spotting the cement at given intervals in the casing as the drill string is pulled out from the well. • The riser and the BOP stack are retrieved. • The well head equipment including the TGB and the PGB is retrieved by cutting the casing about 10 ft. below the well head Either explosives or mechanical cutters may be used. • The process of pulling of anchors begins for an anchor-moored vessel while a D.P. vessel moves to the next location instantly. 2.9.1 Pre-spud Activities Once anchors are laid and pre tensioned to require load in case of moored rigs or positioning of DP rigs at desired location, penetration test and exploration test to confirm shallow gas presence is carried out 50-200m down stream of released location as detailed below: 29


i)

Penetration Test It is carried out to check the seabed formation to ascertain the depth of conductor casing so that it can safely withstand the weight of wellhead, subsequent casing and BOP. It is carried out using a jetting assembly which consist of 12 ¼” bit, bit sub, 3 stands of 8" drill collars, cross over, 5 to 7 stands of HWDP and 5" D/P. The sequence of operations in carrying out penetration test is as under: 1. Bit and bit sub should be painted white for observation by ROV. Space out should be adjusted so as maintain jetting assembly and bit in the hole while making first connection. 2. Gently tag seabed-using ROV and calculate KB to seabed depth with tide correction. Open drill string motion compensator to full stroke and set pressure to compensate at 5000 Kgs. Lower drill string until the bit is lost from view. This depth is known as murk line. 3. Continue to lower the drill string until the bit takes 5000 Kgs of weight and does not settle any more. This depth is known as competent mud line. 4. Initial WOB and flow rate should be low and be gradually raised one at a time when there is no progress. Seabed should be tagged at 5-10 spm and 4-6 KIPS of WOB. 5. Penetration test should be continued without rotation up to the point of refusal. The point of refusal is the point where the formation can withstand 10 T of slack off. 6. Rate of penetration will be dependent on pump strokes mainly. Initial jetting starts with 20 SPM. Keeping parameters same gives a fairly god idea as to when formation begins to change. 7. Plot a graph Depth vs. time & ROP. 8. Based on depth up to the point of refusal conductor casing tally is made.

ii)

Exploration Test Exploration test to confirm shallow gas presence when the drill string is positioned for jetting test off location is also conducted there. It is carried out 50 –200m down stream and down wind side so that if gas is encountered ship can be pulled upstream by anchors or using propulsion to move away from gas zone. Gas plume in shallow gas occurrences has been observed to form a low angle of 10° at the wellhead. Based on this and wind direction location of this exploration test is decided. The exploration test must be carried out upto the sectional target depth of 26" phase. Normally shallow gas pockets are observed from 600 to 900m below seabed. Hence Pilot hole should be drilled upto expected shallow gas/water zone or upto a suitable depth where formation strength is sufficient to withstand increased mud wt. requirement. Prediction of shallow gas by means of geo technical tools is not very reliable therefore, it is a standard practice to drill small size preferably 8 ½” pilot hole. The requirement and procedure for drilling pilot hole for exploration test is as under:

Requirement • A float valve should be installed in bit sub. • As usual a Kelly cock should also be used to arrest gas flow in the pipe. • A minimum of twice the pilot hole capacity of kill mud (10 ppg) should be kept ready. • 50 bbls barite plug to be kept ready. • Cementing unit should be kept in readiness. 30

Offshore Rig

• •

Captain and marine crew be kept ready for moving rig off location if situation arises. ROV should be stationed near the seabed.

Procedure • Normal drilling over this section will be relatively fast hence drilling should be done at a moderate rate so that minor gas flows if any can be identified with ROV. • Always observe the well carefully for gas flow prior to making connection. • If minor gas shows are seen the bit is to be pulled off bottom and observe the well. • If the gas stream continues at a constant rate or diminishes during the flow check then a further 3m can be drilled, circulate bottom up and observe the well. This procedure to becontinued till such time that the gas streams is minimal. • Once safe conditions have been established continue drilling to T.D. • If however the gas flow increases and develops into major flow then the following procedures need to be followed. • Once a major flow has been noted by the ROV maintain circulation through out the gas flow kill operation. • Displace hole volume with 10 ppg kill mud. • Inform captain/chief engineer/DP operator. • If the gas stream does not diminish then pump 50 bbl barite plug at bottom. • If the well is dead or subdued then proceed as with a minor gas flow, reaching to bottom (TD) in 3m interval (prior to that ensure adequate kill mud is made available) or once the well is under control then pump a cement plug above the barite pill and pull back to sea bed to review options. • If failed to subdue the gas flow with barite plug then prepare to pull rig off location. Moving Rig off Location The gas plume in shallow gas occurrences has been observed to form a low angle (10-degree) to the vertical. In 900m of water depth the gas plume will be approximately 158m wide. In such condition immediate action is to be taken to move the ship off the location by atleast 500 m to be out of danger. The ship will be moved upstream but not downward in order to move away from Shallow gas. Marine crew (captain/chief engineer etc) will be aware at all the times while drilling the pilot hole which way the rig will be pulled off location if required to do so. In case enough room is not available we may have to go for emergency winching off with anchors. iii) Spudding Based on seabed conditions either 30" casing alongwith permanent guide base (PGB) can be directly jetted down or 40/42" conductor alongwith float boxes and temporary guide base (TGB) is lowered when seabed is very soft for increasing the resistance to sinking. Jetting of 30" conductor • Based on penetration test results tally is made such that top of PGB remain 1.5m above the seabed at the end of jetting. • Hold PGB with guidelines in place. 31


• • • • • • • • • • • • • • • • • • •

Conductor pipes are run in the conventional manner through PGB with box down and pin up preferably with squnch joints for faster operation. Lower all the conductor pipes. Lower jetting assembly BHA (26" bit + 2 nos. of 9–1/2" d/c + 26" NRRSS + 1 no. of 9-1/2" d/c + 1 std. of 8" d/c + 5 to 7 std. of HWDP + 5" d/p through the 30" casing using C-plate. Jetting assembly length should be so adjusted that bit remains about 1 to 2 ft inside the casing shoe. Make up 30" running tool to the housing. Continue RIH with drill pipes till conductor is nearing seabed-using ROV. Adjust space out to avoid first connection above seabed. Break circulation with seawater and ensure conductor is vertical using bull’s eye of PGB. Jet in conductor following the parameters used for penetration test. Jet down and position PGB about 1.5 m above seabed. Inclination of the conductor should not exceed one degree at any position. In between flush the hole using high viscous gel. Once required depth is reached remove all cuttings using high viscous pill. Allow the conductor to settle/soak for about one hour. Ensure inclination is within 1°. Release casing running tool under surveillance by ROV. Check for any movement of PGB or change in inclination of slope indicator by ROV. Record the distance between rotary table and the top of PGB at corrected tide for further reference. Mark guidelines at moon pool for reference.

Lowering of 40/42" conductor with float boxes and TGB • Weld 40/42" squench connectors with conductor pipe as required with pin up. • Eye pad may be welded to rest on rotary. • Weld 40/42" connector box on the bottom of TGB. • Bring float boxes to moon pool & rest conductor string on float boxes. • Bring TGB to moon pool & latch on to 40/42" conductor. Establish guidelines. • Space out jetting assembly so that it will remain ½’ inside conductor casing. • Make up TGB running tool to the jetting assembly. Lower the same and J on to the TGB. • Secure float boxes to the TGB with bolts & slings. • Check list & trim of rig and adjust slope indicator reading. • Hoist the TGB with D/Works and remove spider beam and RI to sea bed. • Gently touch bottom and jet down to the point of refusal. • Run ROV and confirm the position of TGB. • Check the inclinometer reading. It should be within 1°. • Put paint mark on guidelines at moon pool level. • Un J the running tool and POOH without using rotary. Drilling 36" hole • Make up 26" bit & 36" hole opener and BHA. • Regulate guideline tensioners to 3000 lbs. • Center the string among guidelines using chain pieces and nylon rope. 32

Offshore Rig

• • • •

Alternatively use guidance equipment. Lower string and enter 40/42" conductor slowly. RIH to bottom and drill down to T.D. Make wiper trip. POOH

30" Casing and Cementation • Set the PGB on two beams on the spider deck. • Lower 30" casing through PGB and center with nylon rope and chain on guidelines. • Fill casing, in case ball is used. • Install 30" housing with its running tool. • Break out Running Tool and run drill pipe as stingers using ‘c’ plate. • Make up R/T and open bull plugs of R/T. • Lower and attach the housing to the PGB. • Run the guidelines into guideposts and close the guidepost tops. • Install slope indicator on PGB and drill pipe. Tension guidelines to 6000 lbs. • Lower the string until the PGB is one or two meters under water. • Let air escape and fill casing with s/water. When the casing is full replace bull plugs. • Run casing slowly using D/P as per tally • Run the casing into the TGB using ROV. • Land the PGB on the TGB with the drill string compensator in the mid stroke. • Use ROV to verify that TGB is properly leveled and PGB is correctly mounted. • Carry out circulation and cementation. • Monitor returns during cementation. • Calculate the PGB depth and compare with the depth of TGB. • Check returns after WOC. • Release Running tool and POOH without using rotary. • Circulate thoroughly near housing before POOH. • POOH completely without rotary and recover slope indicator. • In case cementation is poor or 30" casing & TGB is not properly secured at sea bed, it can lead to serious problems. There are cases where even BOP gets lost in the seabed because of this. In such cases cement should be pumped in large quantity in the annulus to avoid complications. iv) • • • • • • • •

DRILLING 26" HOLE Make up BHA using a float valve in the string just above the bit. R/I BHA using either nylon rope and chain or guidance equipment for entering the housing. RIH to the PGB opening. Use compensator to avoid damage to PGB. Also use ROV for monitoring. RIH to casing shoe. Drill down to 20" casing depth with seawater. In between remove cuttings using high viscous gel. Run TOTCO every 100-150 m. Perform wiper trip after drilling to sectional T.D. Fill the well completely with high viscous gel/mud prior to POOH for casing. Also drilling rate should not be very high as due to excessive cuttings in the annulus it caninduce fracture. Further ROV should be deployed at seabed for monitoring any gas coming from the well and around 30" casing. 33


Lowering 20" casing and cementation • • • • • • • • • • • • • • • • • •

Casing is run in conventional manner. The first joint being guided by four nylon pieces & chain for entering in the 30" housing. Set guideline tension to 6000 lbs. R/I required nos. of casing joints. Fill the casing at regular intervals. Make up 18 ¾” well head and set in the rotary Make up and lower required length of stringer using 5" drill pipes using Sub Sea cementing manifold. Make up running tool with wellhead. Continue R/I 20" casing by using 5" d/p. Carefully monitor the entry of shoe in the PGB using ROV. Monitor the approach of 18 ¾’ well head towards 30" housing using ROV. Make up cementing head to last 5" drill pipe and connect cementing hose. Adjust the heave compensator to the weight of the landing string. Land the 18 ¾” well head on the housing. Perform pick up test using compensator. Circulate thoroughly and carry out cementation. After displacement with seawater, check water tightness at shoe. If NRV is used then plug can be bumped to ensure displacement. Check for back flow. If shoe is OK, unscrew R/TOOL and POOH completely after washing well head. Since formation at shallow depth is quite weak cement slurry should not be very heavy as it may induce fracture and due consideration should be given for low seabed temperature while designing cement slurry.

v) BOP LOWERING After completion of 20" casing, BOP is lowered as described below Preparation • • •

Pressure test of BOP is performed up to their rated working pressure. The BOP stack must be in perfect working order when lowered. Surface & BOP mounted accumulator bottles are to be pre-charged with Nitrogen to the calculated pressure.

Lowering • • • • • • • • • • •

Install guide lines in guide posts. Connect the riser, hanging from the hook to the BOP. Mount the riser angle beacon above the flex joint. Pressure test choke, kill, booster & hydraulic lines to recommended test pressures. Carryout function test on both yellow pod & blue pod. Check all functions are in block position. Switch hydraulic power unit to block position. Disconnect junction boxes on hose reels. Increase guideline tension to 8000 lbs. Check that tensioner’s bottle press is at calculated value. Stand by bottles to be at max press. 34

Offshore Rig

• • • • • • • • • • • • • • • • • • • • • • • • •

Hoist BOP stack assembly with the traveling block. Open spider beams & lower the BOP stack & continue lowering by adding riser joints. As each riser joint is added pressure test choke, kill and booster lines. Keep fitting pod hose clamps to the pod hoses and pod lines during BOP lowering. Connect telescopic joint (collapsed) to the last joint of riser. Lower telescopic joint and land it on spider below seal assembly. Add one dummy riser joint and slowly lower the assembly to support ring. Activate lock down dogs (Rotating dogs) of support ring. Move slightly up and down to check that dogs are well in place. Unlatch blocking dogs. Slowly lower the assembly. Check riser tensioner pressure to carry all weight of string minus 20T. Hook up kill, choke, booster and hydraulic lines. Open the D.S. compensator at 20T. Continue BOP lowering monitoring the approach towards guide posts by ROV. Stop descent about 2-3 metres from guide posts according to heave conditions. Check hook load and lower stack carefully on wellhead while monitoring with ROV. Position the stack firmly and activate BOP well head connector to “lock”. Perform pick up test by over pulling up to 20-25 T by means of compensator. Check all riser tensioners pressure. Open inner barrel & rest on spider and disconnect dummy riser. Make up diverter on inner barrel and install in rotary. Connect all hydraulic lines and break out diverter running tool. Decrease guide line tension to 4000 lbs. Carry out diverter operational check.

Testing of BOP stack • • • • • •

RIH BOP test tool using 5" OD drill pipe & land on wellhead. Pressure test choke & kill lines to 7000 psi against failsafe valves. Close the lower pipe ram & perform pressure test to 7000 psi. Carry out BOP test against all rams and annular. After completion of all BOP tests, pull out BOP test tool and install wear busing. Fill up choke & kill lines with NaCl and Glycol mix for gas hydrate suspension.

Further drilling operations are carried out in conventional manner.

35


CHAPTER – 3

DRILLING OPERATIONS 3.1 CHECK LIST FOR SPUDDING 1. Geo Technical Order of the well. 2. Device for making rat hole e.g. turbine etc. 3. Kelly, kelly drive bushings, kelly top sub, kelly saver sub,upper and lower kelly cocks, FOSV, inside BOP, float valve etc. 4. Handling tools like elevators, power tongs, Ezy torque, drill pipe & drill collar slips, drill collar safety clamps according to first phase of drilling. 5. Bits required for rat hole drilling and first phase drilling with all required substitutes. 6. Adequate quantity of HSD, oil and lubricants. 7. Fire fighting equipment duly inspected. 8. Chemicals required for preparation of mud and for controlling its parameters. 9. Supply of water for drilling operations and drinking purpose. 10. Hole opener, if required. 11. Bit breaker for various size of bits to be used. 12. Pressure testing of high pressure lines and air tank 13. Functional check of the instruments like weight indicator, Geolograph, tong torque gauge, rotary RPM meter, rotary torque gauge, etc. 14. Required quantity of proper size of drill string for drilling. 15. Functional check of power generating system, rig & hoisting equipment, mud circulating system 16. Ensure the quality of make up and break up tong lines 17. Functional check of hydraulic cylinder (make up & break out) in case of mobile rigs. 18. Availability of conductor and surface casing as per GTO. 19. Availability of crane for handling casing etc. 20. Safety kit and first aid kit as per the Mines regulations. 21. Well head, BOP stack, choke and kill manifold as per well requirement & tested to its rated capacity. 22. Cementing units and adequate quantity of cement for all exploratory wells in remote areas. 23. Functional check of Twin stop device 3.2 PRE-SPUD CONFERENCE: Spud conference be conducted with representatives of following departments. • Drilling • Mud services • Geology • Logging Services • Health Safety & Environment • Engineering Services • Logistics • Fire Services • Cementing services 36

Drilling Operations

• •

Security Medical Services

3.3 RAT HOLE DRILLING Rat hole is used to place the Kelly. Procedure 1. Take the required quantity of water in mud tank. 2. Connect the turbine /motor with used bit of 12-1/4 inch dia. 3. Guide the turbine/motor/kelly by manila rope which is tied with the mast in the right direction for controlling the back torque of the turbine. 4. Check the water line and mud pump connections. 5. Start drilling a hole through the slot provided for rat hole on the rig floor with water outside the cellar pit. 6. Continue drilling till the depth equal to the length of Kelly + length of lower Kelly cock + length of Kelly saver sub to be placed plus one meter is reached. 7. Case the drilled hole immediately by lowering the rat hole casing pipe of 9-5/8 inch (length should be equal to length of Kelly plus one meter). 8. Keep the height of rat hole casing equal to one metre above the derrick floor for proper resting of the swivel. 9. Always cover this rat hole slot to avoid accident. 3.4 PROCEDURE FOR SPUDDING 1. Connect lower Kelly cock of rated capacity to the lower end of Kelly after cleaning threads and applying proper thread dope. 2. Connect Kelly saver sub to the lower Kelly cock. 3. Record the bit details such as make, type, serial number and size of nozzles . 4. Place the bit breaker on the rotary table and the bit required for spudding, in the bit breaker after checking the condition of the cones. 5. Apply thread dope on the bit. 6. Lock the rotary table’s forward motion by mechanical lock. 7. Make up the bit, bit substitute & Kelly to the required torque. 8. Open the rotary lock, remove bit breaker, and now assembly is ready to tag bottom. 9. Lower assembly and tag the bottom marking kelly. 10. Record the cellar pit bottom. 11. Start the mud pump at slow SPM initially & establish required circulation. 12. Start the rotary table at 20-25 RPM and slowly lower the kelly up to the point marked on the kelly where the formation was touched. Continue drilling with low WOB till bit breaks. Initially drilling is to be carried out with low RPM, WOB and discharge to avoid the erosion of cellar pit area. Later on both pumps can be used. 3.5 DRILLING FOR SURFACE CASING Follow the bit break-in procedures in case of new bit. 1. Continue drilling upto the surface casing shoe depth with optimum ROP, WOB. 37


2. 3. 4. 5. 6. 7. 8.

Pipe connection should be done as fast as possible to avoid sticking of pipe. Ream down the hole if required. Circulate & condition the mud prior to lowering surface casing. Make necessary arrangements for lowering of the casing while circulation. Lower the casing and cement upto surface. Install the well head, BOP Stack, choke and kill manifold. Test well head & BOP as per recommended procedure and pressure.

3.6 CASING TEST PROCEDURE 1. Run in drill string and bit, up to the top of the cement. 2. Break circulation and clear cement upto top of float collar. 3. Circulate and condition the mud. 4. Test the casing at 80% of the burst rating of the casing.. Test duration is 15 minutes. It is considered positive if drop in pressure is not more than 5 %. 3.7 DRILLING BELOW THE SURFACE CASING 3.7.1 Drilling of Cement, Float Collar and Shoe Procedure Make up used bit to drill cement with slick assembly. 1. Drill cement at 2-3 tones of weight on the bit and rotary rpm as 40-50 only. 2. Drill float collar, cement and float shoe carefully. 3. Continue drilling till 0.5 m below the casing shoe, formation should not be opened. 4. Circulate the cuttings out of the well. 3.7.2 Shoe Test This test is done to determine the competency of cement job around the shoe. Procedure 1. 2. 3. 4. 5. 6.

7.

8. 9. 10.

Pull the drill bit in side the casing. Close pipe ram BOP and Kelly cock. Hook up cementing unit with Kill line. Flush the BOP stack, kill and choke lines with water. Close gate valve on choke line. Calculate the shoe test pressure. This is the sum of surface pressure and the hydrostatic pressure of the fluid being used during the test. It should be equal to the hydrostatic pressure at the shoe of the heaviest mud that will be used in the well before running the next string of casing. Pump steadily at a rate of one litre per second till the time test pressure at shoe is reached, plot the increase in surface pressure against volume pumped. (For plotting the graph see leak off test). If the shoe is hermetical, the plot will be linear. Hold the required test pressure for 15 min. The shoe is considered OK if the pressure does not fall more than 10% of the test pressure during this time. Release the pressure through choke line, and measure the volume of fluid recovered and compare this with the volume pumped. Both the volumes should be almost equal. 38

Drilling Operations

11. Open kelly cock. 12. In case the shoe does not hold the required pressure, squeeze cement and repeat all the above procedure for testing shoe. 3.7.3 Leak-off Test This test is carried out to determine the competency of the formation. Procedure 1. 2. 3. 4. 5. 6. 7.

8. 9. 10. 11. 12. 13.

Drill down 1-2 meter fresh formation below the casing shoe. Circulate to clean the hole. Pull the drill bit inside the casing shoe. Connect kelly and close lower Kelly cock. Close the pipe ram BOP. Close kill line and open both the outlet valves of casing head housing. Connect the cementing unit through kill line. The pumping unit should have a graduated suction tank in litres or fitted with a pump stroke counter so that the volume of the mud pumped in can be accurately measured. Start pumping mud in the well at a controlled rate of one litre/sec. Record pressure readings after pumping each incremental volume of 50 litres. Plot these values of pressures against volume of mud pumped on the graph. It will be observed that pressure will proportionally increase after pumping each incremental volume of 50 litres of mud. The first reading of pressure which does not change proportionally after pumping incremental volume of 50 litres is noted. Let it be ‘Ps’ kg/cm2. Hydrostatic pressure due to mud column is calculated at the depth where leak-off is being performed as under: Wm X D Hs = —————— kg/cm2 10

Where, Hs Wm D Ps

= = = =

Then PLOT

= Ps + Hs

Pressure due to hydrostatic head (kg/cm2). Specific gravity of mud. Depth in meters. Surface pressure at which leak takes place (kg/cm2)

10 x PLOT LOT = ——————— gm/cc D After the test is completed, release the pressure and measure the volume of return mud. 14. The volume of return mud for conducting the test should be almost equal to the volume of mud pumped.

39


Points to remember a) Do not keep the pressure and volume data for plotting later on. This may lead to over pumping and formation breakdown. b) The first straight line portion of the graph ‘OA’ indicates elastic deformation of the formation. When the curve starts getting visibly flat (at point A in the fig. 1.24) at the upper end of the plot, the testing is stopped, the point ‘A’ at which this change is noticed is marked. c) The surface pressure should not exceed 80% of the burst pressure of casing. d) When such tests are conducted with heavy mud inside and lighter mud outside the casing, it is the lower part of the casing which is subjected to maximum burst loading. Calculation of Maximum Specific Gravity of Mud: The maximum specific gravity of mud is limited by the LOT pressure at the casing shoe. W max

10 x LOT Pressure at shoe (in kg/cm2) = ——————————————————— Depth of casing shoe (in metres)

3.7.4 Drilling after Leakoff 1. After conducting leak-off test, resume drilling with the drilling parameters as mentioned in GTO. 2. Drill down to shoe depth of intermediate casing . 3. Depending upon well condition wiper trip should be made as and when required. 4. Mud weight should not be allowed to increase beyond LOT value. 5. Totco reading or inclinometer survey should be recorded during each trip and also whenever required. 6. Maintain angle deviation with in 5° for straight hole. 7. Dog leg severity should not be allowed to go beyond 3° per 30 meter 8. Standard logs should be taken before lowering the casing and, as and when required. 9. If required, rise of cement may be changed as per the well condition. 10. Centralizers should be placed as per the plan. 11. After casing has been lowered and cemented, observe the WOC as per the plan or and casing on casing hanger (Sea Bed) immediately after cementation. 12. Install & test well head. 3.7.5 Intermediate Casing Test After testing of BOP, choke & kill manifold etc, testing of intermediate casing is to be carried out as follows. 1. Run in drill string and bit, up to the top of the cement. 2. Circulate and condition the mud. Drill/ clear up to top of float collar. Circulate for hole cleaning. 3. Test the casing, test pressure should not exceed minimum of the following. a) 80% of the internal yield pressure of the weakest section of the casing lowered. b) Maximum allowable casing head pressure. Note : If casing shoe is drilled out, test pressure should not exceed the formation fracture pressure at the shoe. Test duration is 15 minutes. 40

Drilling Operations

3.8 DRILLING BELOW INTERMEDIATE CASING 1. Conduct leak-off test and resume drilling 2. Continue drilling the hole (same as above) till it reaches the depth where next intermediate casing is to be lowered. 3. Coring to be done as per requirement. 4. Mud weight should not be allowed to increase beyond LOT value. 5. Totco reading or inclinometer survey should be recorded as when required. 6. Maintain angle deviation with in 5° for straight hole. 7. Dog leg severity should not be allowed to go beyond 3° per 30 meter 8. Standard logs should be taken before lowering the casing and, as and when required. 9. If required, rise of cement may be changed as per the well condition 10. Centralizers should be placed as per the plan. 11. After casing has been lowered and cemented, observe the WOC as per the plan or land casing on casing hanger (Sea Bed) immediately after cementation. 12. Install & test well head. 3.9 HERMETICAL TESTING 1. Displace the mud in the well with water and wash the well till clear water starts coming out of the well. In case the differential pressure between mud & water at bottom is unusually high, displacement should be carried out in steps. 2. Disconnect the circulation line from string. 3. Connect cementing unit to string & test surface equipment & lines. 4. Close the BOP & annulus well head valves. 5. Pump water at steady rate of one liter per second. 6. Pressurize casing unto required test pressure by pumping water at slow & steady rate. Hold this pressure for 30 minutes. Test Pressure Test pressure should not exceed minimum of the following: 1. 80% of the internal yield pressure of the weakest section of the casing. 2. Maximum allowable casing head pressure 3. Maximum allowable annulus surface pressure (MASP) while circulating out the kick below shoe. 4. The pore pressure less the pressure exerted by the column of the gas as production requirement. 5. Test duration is 30 minutes. 3.10 OPERATING PRACTICES OF EQUIPMENT 3.10.1 Procedures for Connecting Kelly- Swivel and Hook The Kelly is connected to the swivel through a left hand substitute. The swivel hangs in the hook with the help of a bail. 1. Engage the rotational lock in the desired direction (hook tongue facing towards the swivel bail) of the hook. 41


2. Keep the hook at a desired height so that the hook’s tongue can enter the swivel bail on pushing the block and hook system towards the swivel. When the hook’s tongue enters the bail of the swivel, lift it up slowly and put the lock of the tongue in position. After the positioning of the lock at correct place, lift the block and hook in slow speed. 3. Care must be taken to prevent the hitting of the Kelly into the pipe, resting on the rotary table. 4. Hold the Kelly by a winch line to prevent its sudden coming out from the rat hole housing. 5. While pulling out the Kelly from the rat hole, the casing line should not be rubbing the members of the mast. 3.10.2 Procedure for Disconnecting Kelly and Hook 1. After disconnecting from drill string lift the Kelly sufficiently and put thread protector on Kelly saver sub. 2. Pull it with a winch line towards the rat hole housing. 3. Lower it into rat hole slowly. 4. The hook is freed from the swivel by opening the tongue of the hook and bringing out the hook from the bail. Then free the block and hook. 5. The lock which restricts the rotation of the hook is then disengaged and thus the block and hook become ready for handling the drill string or for doing any auxiliary job. The tongue lock of the hook is then closed. 3.10.3 Checking of Master Bushings and Rotary Slips To determine effective gripping action of the rotary slips and master bushings follow the simple field test procedure as 1. Pick up Kelly, wrap the pipe gripping area with a white paper and set the slips against the paper. 2. Pick up, remove slips and carefully examine gripping area to determine length, circumferential amount, and uniformity of holding by gripping elements. 3. If the rotary master bushings and slips are in good condition, a uniform gripping can readily be observed, matching the length of the slip being employed. Under such conditions, the total transverse load would be equally distributed over the maximum slip area and crushing will not occur. 4. If the gripping pattern is such that it does not conform to the entire slip, either the slips, or the master bushing or both are out of specification. To determine which is at fault, the same tests should be repeated with a new or like new set of rotary slips. If this corrects the problem and the pattern is uniform, it is the rotary slips which were at fault. On the other hand, if on using the new or like new rotary slips, the uniform pattern is not observed, and it is evident that the master bushing is out of specification. It is necessary that the slips and/or the master bushing be properly repaired or replaced immediately. SLIP TEST 1. A slip test is an invaluable aid for determining the degree of rotary equipment wears. This test should be performed every three months and each time a new master bushings or set of slips with set of new dies is put into service. 2. For accurate results, use a hook-load of at least 100,000 pounds: 42

Drilling Operations

3. Clean an area of pipe where there is no insert marks and clean slip inserts with a wire brush. 4. Wrap two layers of test paper or mud sack around the cleaned section of pipe. Use adhesive tape at the top and bottom of the paper to hold it in place. 5. Place the slip around the pipe against the paper. Hold the slips in place while the pipe is being lowered at normal speed. 6. After the slips are set, hold them firmly around the pipe as it is raised. The slips should be carefully removed to prevent damage to the paper. Then carefully remove the paper. 7. Observe the second layer of the paper because the outside layer will have misleading slip impressionms. 8. If a full insert contact is indicated, the master bushing and slips are in good condition and no further analysis is necessary. 9. If there is no full contact, the test should be conducted with new slips. If the second test results in full contact, discard the old slips because they are worn, crushed or otherwise distorted. 10. If the results of the second test indicate top contact only, the master bushing and/or bowls are worn and should be inspected for replacement. 11. Change the dies of the old slip and again carry out the test to check the condition of slip. If problem persists discard the old slip. 12. Never resharpen inserts. Doing so causes improper contact with the pipe, resulting in both pipe and slip damage. 13. Never catch the tool joint box in the slips when the driller slacks off. This often happens when coming out of the hole and the driller does not pick up high enough for the slips to fall around the pipe properly. 14. Torquing tool joints properly is the most important single factor in prevention of tool joint troubles. . 15. Torque measuring equipment should always be used to prevent under or over torquing. 16. Never use one tong as it greatly increases the possibility of bending or “hooking” the pipe at the rotary. 17. Also line pull should not exceed recommended makeup torque with tongs at 90 Degrees to the jerk line. 3.10.4 Proper Slip Handling Techniques 1. Stop the downward motion of the drill pipe with the brake not by the slips. 2. Do not let the slips ride the pipe. This not only damages the slips, also reduces the configuration of the gripping elements. 3. Do not use slips designed for one specific size of pipe on any other size of pipe. 4. Avoid using old & new dies in combination. 5. All damages to rotary slips should be immediately attended to. 6. If slip is not holding the pipe due to worn out dies, the same must be replaced immediately. Slippage of pipe through the slips due to worn out inserts can result in dropping the pipe. From time to time, this occurs though it is difficult to believe. 7. While R/I in the hole, ensure that the slips do not accidentally catch the drill pipe.

43


3.10.5 Proper Use Of Drill Pipe Tongs 1. When making up or breaking out drill pipe stands without back-up tongs, the pipe may slip enough to make bad scars. Such scars are usually spiral, because the pipe is dropping while it is slipping. 2. Keep the tool joint as close to the rotary table as possible during makeup and breakout. There is a maximum height that a tool joint may be positioned above the rotary slips and the pipe resist bending. This is required when maximum torque is applied. 3. Keep in mind the factors governing the height limitation: a. Angle of separation between tongs. b. Minimum yield strength of the pipe. c. Length of the tong handles. d. Maximum recommended make-up torque. 4. The tongs should be placed either at an angle of 90 degree or 180 degrees apart. 3.10.6 Kelly Drive Bushing Fit 1. The life of the drive section is directly related to the Kelly fit with the Kelly drive. A square drive section normally will tolerate a greater clearance with acceptable life as compared with hexagonal section. 2. New roller bushing assemblies working on new Kelly will develop wear patterns i.e. essentially flat in shape on the driving edge of the Kelly. Inspection Inspection procedure for used Kelly: 1. Examine junctions between upset and drive section for cracks. 2. Check corners of drive section for narrow wear surface particularly on hexagonal kelly. If wear surface does not extend at least 1/3 across flat, the Kelly drive bushings should be adjusted if possible and/or examined for wear. 3. Kelly straightness can be checked either of two ways: • By watching for excessive swing of the swivel and traveling block while drilling, or • On hexagon Kelly’s, use the same method except Kelly will need to be placed in 120 degree V-blocks so that face of drive section is vertical and deflection measurements taken on three successive sides (turning Kelly through 60 degrees each time). 3.11 TRIPPING PRACTICES 3.11.1 Procedure for Making Up Joints 1. Clean and inspect the threads of the pin and box joints of the drill pipe, drill collar, if found all right, apply thread dope. 2. Initially tighten d/p & tubing using spinner. 3. Drill collar joints to be tightened initially with the help of chain tong. 4. Use the safety clamp for plain D/C. Measure & record their length, ID and OD in BHA book. 5. As the upper joint is tightened to the lower joint, the drill-o-meter needle will show that the pipe is in tension. When this happens the block should be released slightly so that the weight indicator shows weight equal to that of an empty block and the drill collar. 44

Drilling Operations

6. Finally the D/C joints should be made up to the specified torque using both the tongs/ easy torque. 7. The drill string is then hoisted sufficiently to permit the removal of slips. Note: 1. Clean & dry the joint which is being added to the string. 2. The box threads and shoulders should be doped, distributing the compound over the threads and the mating surfaces preferably with a round, stiff bristle brush. 3. Do not dilute the thread compound for the ease of application. Dilution of thread doped will reduce the amount of available metal filler and make the compound ineffective. 4. Pipe should never be made up by reversing the rotary table. 3.11.2 Procedure for Breaking Up Joints Apply lubricant on the back of the slips to avoid sticking in rotary table. 1. Tongs shall never be fitted on the body of the drill pipe. 2. Crack the D/C joint with the help of jerk line (or Ezy torque if available). 3. Break the joint completely with the help of spinner and do not use rotary for the same. POINTS TO REMEMBER • Evaluate bit condition after P/O to decide the new bit. • Tripping should be done at slow rate in open hole in view of swabbing and surge specially in 8½ inch and lower hole sizes. • Mud system should always be in good condition. • Before tripping out, consider the margin for ECD. • If high mud weights are being used, the yield point is normally kept optimum to reduce swabbing and surges. • Mud conditioning should be done in coordination with the tripping plan. • Consider the influence of Yield Point on Trip Margin Yield point MWtrip = MWbal + —————— 11.7(Dh-Dp) Where MWtrip MWbal Dh Dp • • •

= = = =

Estimated mud weight (ppg) to trip that will over come swab effect Mud weight (ppg) to balance formation pressure (no trip margin) Hole dia in inch D/P dia in inch

To prevent wet pull out slug should be pumped in, if well condition permits. Ensure mud fill up/return with the help of trip tank only and as per trip sheet. Prepare trip schedule prior to running in or pulling out.

3.11.3 Good Practices to Break Circulation after Round Trip 1. Keep pipe moving (rotating/reciprocation). 2. Start pump slowly, and record any U-tube pressures required to initiate flow or to kick float open. 3. Pressure-up new joint before lowering below rotary table. 4. Tag bottom carefully to prevent bit damage (or plugging of nozzles) when using a PDC bit. 45


3.11.4 Reaming It is the process of re-drilling of left over formation and is essential in the process of deepening of the hole. Procedure The frequency of reaming is established depending upon the ROP and method of drilling. Prior to making a fresh connection the hole should be reamed for the length of the kelly. For wells being drilled in hazardous and complex conditions, the frequency and technology of working over drilled intervals may be adopted as per the conditions of that well . 3.12 DRILL STRING AIDS 3.12.1 Drill Pipe Wiper These are installed by splitting & pulling apart the ends and pushing on to the drill pipe till the wiper’s groove for the pipe is reached to facilitate the cleaning of mud from the surface of drill pipes during pulling out. It should be installed after pulling the first ten stands from the bottom in order to observe the swabbing in the well during the initial pull out. 3.12.2 Tong Pull Back During round trip operations, while opening or tightening the joints, tongs are required to be fixed again and again on the tool joints of the pipes. The tong pull back saves time by automatically repositioning the tong for another take-up. It is very useful while lowering casing and tubing. 1. Hook one end of the loop of ‘tong pull back’ over tong line pin at the end of lever-arm or with the help of a manila rope. Tie one end of the tong pull back to the end of the lever of the tong. 2. Tie the other end of the tong pull back to derrick leg or any other fixed place with the help of a wire line or a manila rope. 3.12.3 Balancing Strap This is used to keep the centre-latch elevators balanced in any desired position for the ease of operations. 1. Fix the U-bolt assembly on the elevator link at a suitable height. 2. Put one end of the strap on the bolt assembly. 3. Attach the other end of the strap to the elevator handle. 4. Adjust the height of the U-bolt assembly so that the elevator remains in horizontal position when in open or closed position. 5. Tighten the U-bolt assembly.

46

Hydraulics

CHAPTER - 4

HYDRAULICS Proper hydraulics is one of the main factors, which contributes in improvement of penetration rate of bit. Proper hydraulic programme consist of selection of most appropriate nozzle sizes and circulation rate for an existing set of conditions found at the rig 4.1 MINIMUM ANNULAR VELOCITY It is important to avoid large pressure losses through drill string and annulus so that the maximum of the available pump’s hydraulic horse power (HHP) may be utilized at the bit. The losses through drill string and annulus are directly proportional to the square of the circulation rate (approximately), hence to avoid large pressure losses through them, the circulation rate should be held as low as possible, consistent with effective cutting removal and proper utilization of the pump power. Drilled cuttings are heavy and travel upward initially but tend to fall thereafter. This downward velocity of cutting is called slip velocity. Annular velocity/Circulation rate Discharge Q = A*V where A is the annular cross-sectional area and V is the annular velocity. Circulation rate = 2-3 lit/Sec/Inch of hole size-

.....(1)

431.5 Annular velocity (M/min) = ————————————————————— Hole sizes H (in) X Mud weight W ( gm/cc)

.....(2)

Circulation rate that can transport cuttings to the surface is determined by carrying capacity of drilling fluid, rate of penetration and the volume of drilled solids. It depends on hole size, drill string size and annular velocity. Maintain annular velocity about twice the slip velocity. Pump stroke can be determined by, Total circulation rate Nos of strokes per min = ———————————————————— No. of mud pumps X discharge per stroke

.....(3)

There are certain values of annular velocity used for different hole sizes; HOLE SIZE

ANNULAR VELOCITY

26”

5-9 M/min

17-1/2”

18-30 M/min

12-1/4”

21-33 M/min. If drilling with water, 50 M/min is adequate.

8-1/2”

36-54 M/min. However in order to optimize the hydraulics, higher velocities can also be used.

6”

42-60 M/min is adequate. Avoid turbulence.

4 3/4”

42-66 M/min is adequate.

47


Note : If the desired annular velocity is not achievable due to break down of one of the pumps, then it is advisable not to carry out further drilling. The minimum nozzle velocity required for jet drilling is about 54 M/sec to 69 M/sec. The following rule of thumb may be used. Bit size in inches

Minimum nozzle velocity, M/sec per inch of diameter

6-3/4 – 9

8

9-5/8 – 10-5/8

7

11 and larger

6

Important Hydraulic Formulae; 1. Annular Velocity V

1.97 Q = ——————– M/min. (Dh)2- (Dp)2

Q = Circulation Rate lt/min, Dh = Hole dia.in Inches , Dp = Pipe OD in Inches 2. Surface Equipment Pressure losses P1 = CW(Q)1.86 x 0.019 Kg/cm2 C = Friction Factor, W = Mud Weight In SG Equipment type 1 2 3 4

C 1.0 0.36 0.22 0.15

3. Drill String Bore Pressure losses 0.02 WLQ1.86 P2 = ——————— Kg/cm2 d4.86 d = ID of Pipe in Inches, 4. Jet Nozzle pressure losses -2

(WQ)2 x 1.356 X 10 P3 = —————————— Kg/cm2 (An)2 An = Area of nozzles in sqare inches

48

Hydraulics

5. Annular pressure losses WLV2 P4 = 2.9640 X 10-6 ———— Kg/cm2 Dh-Dp 6. Jet Velocity Vn =

1.5505 Q —————– m/sec An

7. Hydraulic Horse power PxQ HHP = –––––––– 450 8. Viscosity Correction Factor 0.14

⎛ PV ⎞ ⎟ ⎝W⎠

VCF = ⎜

Optimization of hydraulic programme Calculate the following parameters: Actual pressure loss through bit nozzle 1. % BHHP = ———————————————————— x 100 Stand pipe pressure Actual pressure loss through bit nozzle (kg/cm2) 2. BHHP (lit/sec) = —————————————————————— x Circulation rate (Lit./s) 5.97 x (hole diameter in inch)2 1.55 x circulation rate (lit/sec) 3. Jet velocity (m/sec) = ——————————————— Area of nozzles (inch2) In case of soft formation annular velocity is important, while in case of hard formation jet impact is important. For an optimum hydraulics programme the above parameters should have a value within the following range, i)

% BHHP

=

50 to 65%

ii)

BHHP/sq. inch of hole size

=

2 to 5 (lower value for hard formation, higher value for soft formation)

=

100 to 168 M/sec.

iii) Jet velocity

49


Procedure to achieve best hydraulic 1. Select an annular velocity appropriate for a particular hole size from tables . 2. Select circulation rate for the annular velocity depending upon the hole size and BHA used. 3. Calculate SPM required based on the discharge of the rig pump. Select proper liner size. 4. Calculate system pressure losses using tables (except for pressure loss through nozzle) Correct the same for actual mud weight and viscosity. 5. The pressure available for nozzle selection is the difference between operating pressure limit (depending on surface equipment and liner chosen) and actual system pressure losses. 6. After nozzle size has been chosen, record pressure losses through nozzles from the tables available in the data book, correct the value for mud weight. 7. Calculate the three parameters stated above for optimization of hydraulic programme. If the values are within limits, then our nozzle selection is optimum. If the values are out side thestated limits, change the variables namely annular velocity and circulation rate so that hydraulic programme is optimized within available constrains.

50

Drilling Bits

CHAPTER - 5

DRILLING BITS 5.1 TRI CONE ROLLER (TCR) BIT The performance of the TCR bit is dependent on many factors such as selection of proper bit, operating parameters and hydraulics. Consider the following points while using TCR bits. 1. Select the bit on the basis of lithology/formation to be drilled. 2. Select the tooth bit with tungsten carbide inserts on gauge if sand streaks are expected in the formation. 3. Select a tungsten carbide insert bit with minimum or no offset when drilling hard and abrasive lime stone, hard dolomite, chert, pyrite, quartz and basalt etc. 4. Select a bit with long widely spaced teeth where balling tendency of the formation is expected. 5. Check the bit for any physical damage. 6. Record the bit serial No., type, diameter before lowering into the well. 7. Use lifter for handling TCR bit to avoid damage of threads. 8. Use proper bit breaker for tightening & breaking the bit. 9. Do not consider a new TCR bit as oversized on checking with the ring gauge as TCR bits can have positive tolerances. 10. Do not use rotary table for initial tightening of the bit. 11. Ensure free rotation of rollers in case of standard bearing bit. In case of sealed bearing, do not try to make rollers free. 12. Clean reservoir cap equalization ports of sealed bearing bits before running in a hole. 13. Use proper type and size of substitute with bit. 14. Tighten the bit at recommended torque. 15. Lower the bit slowly into ledge, dogleg and at liner hanger top. 16. Reaming with TCR bit should be done with low WOB and low RPM. 17. While approaching well bottom, rotate the bit and circulate mud to clear out any fill and to avoid plugging of the nozzles. 18. Break the bit at bottom with low WOB & slow RPM for 1-2 m to establish bottom hole pattern. 19. Conduct drill off test to ascertain optimum drilling parameters. 20. WOB can be increased up to the recommended value or until the desired ROP is achieved. 21. Gradual breaking of sealed bearing bits will enhance the life of the bit. 22. Use of junk sub above the insert bit will help in avoiding the damage to the bit due to presence of broken inserts and previously left metallic junk in the well. 23. Use of junk sub above last mill tooth bit run prior to drilling with an insert bit is recommended. 24. After pulling out bit, wash the teeth, cones & around nozzles area to grade the bit judiciously. 25. Use 2/3rd rules to find wear of tricone roller bit with a ring gauge. 26. Relate dull bit grading to operating practices, formation characteristics and bit design to improve the next bit selection.

51


27. 28. 29. 30.

Do not try to push the bit through tight spots. Do not load the bit abruptly. Never put excessive WOB and high RPM while reaming. Do not touch well bottom with a sudden jerk/impact.

5.2 POLYCRYSTALLINE DIAMOND COMPACT (PDC) BIT The performance of the PDC bit is dependent on many factors: Selection of proper bit, operating parameters and hydraulics PDC bit running procedures are quite different from roller cone bits or even natural diamond bits. Consider the following while using PDC bits. 5.2.1 Hole Preparation 1. Check the condition of the pulled out bit for a) Physical damage b) Cutters condition and c) Gauge. 2. If inserts are found severely damaged and bit is under gauge then clear & condition the hole with roller cone bit and junk sub/junk basket. 3. Prior to running in with a new PDC bit run junk sub with last bit to clear bottom hole for any metallic junk. 5. It is advisable to use TCR bit with junk basket in case of metallic junk or severely under gauged hole is observed prior to running of PDC bit. 6. Drill cement and casing shoe with used TCR bit, then lower PDC bit to drill further. 5.2.2 Making Up PDC Bit 1. Take out PDC bit from its box and place it on a piece of plank carefully and do not roll or place the bit directly on steel surface to avoid damage to cutters /inserts. 2. Check PDC bit for any damage of cutters, inserts and nozzles. 3. Record the bit make, serial No., bit type and diameter before running into the well. 4. Ensure that all nozzles of bit are of required size & properly tightened. 5. Clean bit pin and apply recommended thread dope compound. 6. Use the bit breaker of the same company to which PDC bit belongs. 7. Place the bit with breaker in the rotary table and make up the drill collars string to the specified torque as per API. 5.2.3 Tripping In 1. Care must be taken while running in PDC bit through surface equipment as PDC bit being one piece and is not flexible as roller cone bit. 2. Pass through tight spots very slowly as striking ledges can damage gauge cutters. 3. In case of tight spots, pick up Kelly and run pump at slow rate as compared to drilling. Keep rotary speed at about 60 RPM and proceed slowly through a tight spot with maximum WOB 1.5 -2 T. Avoid high torque while reaming. 4. Avoid PDC bit for reaming long interval in case previous bit was observed significantly under gauged. 5. While tagging bottom with PDC bit, keep on circulating at required pump SPM & RPM to avoid plugging of the bit. 52

Drilling Bits

6. Keep constant watch on rotary torque & weight indicator while tagging bottom. If sudden increase in torque is observed at well bottom due to aggressive cutting structure of PDC bits, Pick up the bit 6’’ to 12’’ off bottom. Circulate out the cuttings before resuming drilling. 5.2.4 Breaking- In 1. New PDC bit should be slowly set on well bottom at a slow rotary speed (50-60 RPM) & WOB not more than 2 T to establish bottom hole pattern. 2. If bit does not perform well after few minutes then increase the W. O. B. in steps till it performs well. 3. Increase the WOB to the recommended value to achieve the desired ROP. 4. Optimum WOB necessary for PDC bit is 2/3rd of that required for a roller cone bit. 5.2.5 Drilling Procedure Rotary torque is effective parameter to know the activity at the bit face at bottom. In soft formations, there may be indications of rotary torque even if the bit is off bottom. Steady torque is observed while drilling through shale & heterogeneous formations. Varying surface torque is observed in layered formations. Following steps are to taken while drilling. 1. Reduce the WOB if torque increases considerably while drilling through sands/fractured formation. 2. In order to avoid the bit slip phenomena in plastic/soft formations reduce the WOB and increase rotary RPM preferably. 3. When there is reduction in ROP, more WOB should be applied in increments of one ton to take care of wearing of PDC cutters. 4. Carry out drill off test to achieve optimum ROP. 5. WOB should be increased before increasing the rotary speed in order to attain maximum depth of cut by PDC cutter. This will help in preventing bit from becoming unstable, thereby stopping backward whirling motion. 6. In softer formations increase in rotary speed results in better ROP but reverse may occur in harder formations as PDC cutters are unable to ‘dig- in’ beyond a certain threshold RPM limit. Making Connections 1. Maintain normal circulation rate when Kelly is raised. 2. Bit should be washed back to bottom slowly at normal circulation rate. 3. Avoid sudden release of the drill string as this may result in damage to the PDC cutters.

53


CHAPTER - 6

WELL LOGGING Well logging is a technique to record geophysical properties of rock as a function of depth. It is accomplished by moving a down hole logging probe and recording its sensor output at the surface through an electrical cable. The borehole logging probe or the well logging tool relates to a particular physical property of the rock and mud system. The well logging system consists of (a) Down hole-logging tool, (b) Surface computer system and (c) Wire line cable for transmitting down hole signal to surface system. Majority of logs are recorded while pulling the tool upward in the borehole. The logs are recorded both in the open hole as well as in the cased hole, though with different objectives. •

There is a large variety of logging tools meant for different types of measurements. Generally these tools are named according to what parameter they measure or to the physical process involved during their operation e.g. the tool which measures resistivity of the formation is generally referred to as Resistivity Tool.

6.1 PURPOSE Logging is conducted to locate reservoir rock and to evaluate its viability as hydrocarbon producer.. The most common reservoir rocks are sandstones (elastic rocks) and limestone and dolomite (carbonate rocks). The effectiveness of a rock as a commercial hydrocarbon producer depends upon its following properties: a) Reservoir properties- Porosity, permeability and fluid saturation, which help in describing the texture and producibility of reservoir and are essentially determined for estimation of oil and gas reserves. b) Physical properties- Electrical resistivity, self-potential (SP), radioactivity, elastic wave propagation etc. help in describing nature of rock and its saturating fluids. The well logging techniques are employed to measure these physical properties of rocks directly in the borehole. The well log data interpretation is the methodology to translate in-situ measured physical properties into reservoir parameters, such as porosity, fluid saturation, permeability and other geological parameters in a more realistic manner. 6.2 RESERVOIR PROPERTIES Porosity: When sediments are deposited and compacted they do not form a solid mass. There exists some space between the grains called inter granular pores. The amount of space or voids as a percentage of total volume of formation is called the porosity. The formation fluids e.g. water, oil and gas accumulate in these voids. The larger the porosity more is the amount of fluid a formation will contain. It is measured in percentage. Permeability: It is an important directional property that permits fluid flow through interconnecting pores of the rock. It is defined as a measure of fluid conductivity of the rock. It is measured in milidarcy/darcy. 54

Well Logging

Water Saturation: Water wet rocks are more common in oil fields as water is found present practically throughout reservoir rocks whether they contain oil or gas. Therefore fluid distribution in a reservoir is traditionally expressed in terms of percentage of water saturation denoted as Sw. Other fluid saturations are inferred from water saturation. 6.3 PHYSICAL PROPERTIES Electrical Resistivity All sedimentary rocks are characterized by mineral composition, which constitute their solid framework. They are highly resistive to the flow of electricity when free from conducting minerals because the solid material such as mineral grains, rock matrix and cementing material exhibit high electrical resistivity when dry. The conduction of electricity in clean porous sedimentary rocks is due to the presence of electrolytic fluid saturating the rock such as water. Electric current flows in porous rock through saline water contained in the pore space. Therefore electric conductivity or electric resistivty of rocks depends upon following factors related to water properties: a) Salinity and ionic composition of the water associated with the rock- The resistivity decreases with increase in the salinity. b) Water content of the rock i.e. porosity and the water saturation- Higher the water saturation, lower the resistivity. c) Sub surface temperature of the rock- Increase in the rock temperature increases the ionic mobility thereby decreasing the resistivity of formation water. • The presence of clay minerals, which conduct electricity when wet, also influence the resistivity of the rock. The pore space geometry that is represented by rock porosity constitutes three-dimensional complex networks interconnecting the pores in twisting and tortuous manner. This increases the length of current path through rock resulting in increase of rock resistivity. Radioactive Properties The rocks exhibit natural gamma ray (GR) activity by virtue of dissemination of radioactive elements K, Uranium, thorium and their associated radioactive elements found in sedimentary rocks. Potassium the major contributor to natural GR activity, is present as an integral part of clay. Uranium and thorium are adsorbed at the clay lattice surface. Distribution of K, Uranium and Thorium is thus caused by sedimentation and different geochemical activities. It is therefore observed that clay due to their high adsorption property exhibit highest radioactivity among all sedimentary rocks. The variation of natural GR in different rocks act as an effective tool to differentiate the lithology. Apart from natural radioactivity, artificial radioactivity can be induced in the rocks by exciting rock atoms by bombarding either fast neutrons or gamma rays on to rock medium. Analysis of artificial radioactivity enables to get information on various petrophysical properties of the rocks. Neutron excitation method involves slowing down (thermalisation) of neutrons after interaction with the rock and emission of captured gamma rays. This provides information on porosity and lithology. The gamma ray interaction method involves attenuation of gamma rays by photoelectric absorption and Compton scattering, which provide information on rock density and lithology. The formation density thus measured, is one of the major parameters for porosity determination.

55


Elastic Wave Propagation The characteristic feature of sound waves is that they change speed with the change in media (density) through which they travel. In well logging the acoustic properties of the rock and the fluid present in its pores can be used to evaluate various characteristics. Porosity being the most common parameter is determined using elastic wave propagation method. 6.4 OPEN HOLE LOGGING The logs recorded in open hole, provide a direct measurement of a number of physical properties of rocks based on different tool principles. The quality of logs taken depends on borehole environment which are described below: Borehole Environment • The drilling fluid or the mud maintains hydrostatic pressure over and above the formation pressure against permeable zone to prevent blowout and also to protect well bore wall collapse. Bit action, mud circulation, reaction of mud with formation and several other technical reasons create rigidity in borehole walls, hole deviation and mud infiltration into porous and permeable beds. This infiltration creates invaded zones near the well bore and creates mud cake against permeable zones. • Log values measured under such conditions are called apparent values, as these depart from true values of physical properties of rocks due to effect of borehole environment. • The most important properties of mud having direct bearing on logging data are mud density, viscosity, mud cake formation and mud filtrate salinity. The basic principles of frequently recorded open hole well logs and their measured parameters are as follows. 6.4.1 Caliper Log The caliper log records the borehole size variations with depth. The caliper log thus is useful in correcting some of the logs which are very sensitive to hole size variations 6.4.2 Spontaneous Potential (SP) Log The SP log records the change in naturally occurring potentials as a function of depth in the borehole. The SP log is recorded by measuring the potential difference between an electrode in the borehole and a grounded electrode at the surface. It is measured in mili-volts. All SP changes are measured from shale base line as absolute value of shale potential is of no interest and the curve is monotonous. Against permeable zones it deviates from shale base line either to left (negative SP) or to right (positive SP) depending upon formation water salinity being greater or less than mud filtrate salinity respectively. The SP will not develop in wells where no salinity contrast exists between mud filtrate and formation fluid. SP log is used to determine sand-shale bed boundaries, formation water salinity and degree of shale ness. 6.4.3 Gamma Ray (GR) Log The gamma ray log is indicative of the intensity of natural radioactivity of rocks. The GR is indicative of the rock type present. Shales have higher GR values compared to sandstones or limestone. GR log is used in identifying bed boundaries e.g. shale and sand sequences.

56

Well Logging

GR log is commonly used for depth correlation as it shows similar sharp features in two different logging runs. It is also used in depth correlation with cased hole logs. GR log is most widely used for well to well correlation as geological signatures on gamma ray are present over a wide area. The GR log finds an important application in estimation of shale volume in shale formations. GR log is presented as gamma ray in API units. 6.4.4 Resistivity Log A resistivity log measures the formation resistivity, which is defined as resistance to electric current flow by unit cube of formation. The resistivity of undisturbed formation is required to quantitatively evaluate the fluid saturation of the formation of interest. The formation resistivity is measured either by sending low frequency current (e.g. Latero tool) or high frequency electromagnetic waves (e.g. Induction tool) into the formation. In Latero tool the current is focused to flow horizontally in lateral direction perpendicular to tool axis. This tool is used in conductive mud. In Induction tool the current in the transmitter coil of tool generates an induced current loop in conductive formation. The strength of induced current is proportional to the formation conductivity. The induced current in turn generates secondary induced electromotive force (voltage) in the measuring coil. Thus measured induced voltage is proportional to the conductivity of formation. Induction tool is ideal for logging in fresh mud or in gas filled holes. 6.4.5 Sonic (Accoustic) Log The sonic log is based on propagation of accoustic wave through formation. The speed of sound wave is reduced by presence of fluids in the formation pores, depending upon their volume. Therefore this speed or travel time is used as a measure of porosity of the formation. In acoustic logging tool the accoustic waves of ultrasonic frequency are sent into the formation by the transmitter and accoustic travel time of compressional wave arrival at the receiver is recorded. The travel time is influenced by framework of the rock and fluid filled pore space. 6.4.6 Density Porosity Log The density logging tool measures electron density of the formation. The porosity estimation in density log is referred as ‘Density porosity’. It depends on lithology of the rock matrix and density of the fluid occupying the pores. The density logging tool works on the principle of ‘ interaction of gamma rays with matter’. Gamma rays are emitted from an artificial GR source (Cs137), which are bombarded on the formation. The gamma rays loose their energy depending upon the electron density of the formation (proportional to the formation density). The slowed down gamma ray is measured by the GR detector in the tool. The tool is calibrated with standard density materials and the detected GR count thus is directly presented in terms of bulk density of the formation. 6.4.7 Neutron Porosity Log The neutron log works on the principle of neutron interaction with the nuclides of the atoms present in the formation. The hydrogen atom having the same mass and size that of neutrons, is most effective in slowing down the neutrons. The tool responds basically to hydrogen nuclei in the formation, which can be related to total porosity of the formation. The neutron logging tool contains a neutron source (Am-Be) which emits neutrons which are bombarded on the formation. The detector of the tool detects either the slowed down neutrons (called thermal neutrons) or the captured gamma rays, depending upon the type of detector used. The log is usually presented with density log in compatible scale. 57


S.N.

Name of the log

Measured parameter

1. 2. 3. 4. 5. 6.

Caliper log Spontaneous Gamma ray log Resistivity log Sonic (acoustic) log Density Porosity log

7.

Neutron porosity log

Bore hole size variations Sand-shale boundaries/degree of shaleness Sand-shale boundaries/well to well correlations/depth correlation Measures resistivity/Support tool along with other tools. Porosity Bulk density of the formation (rock metrix + fluid occupying the pores) Porosity/gas zones

As the number of detected thermal neutrons or gamma rays is controlled by the hydrogen concentration in the formation, therefore it is a measure of porosity in terms of presence of hydrogen atoms present in the pore fluid (water or hydrocarbon). Since hydrogen index of oil is very near to one, the neutron log does not differentiate much between oil and water. However hydrogen index of gas is small compared to that of water. The neutron log responds to gas indicating very low apparent porosities. This feature is used to identify gas zones. The density log gives apparently higher porosity in gas zones. The neutron-density log overlays in gas zone clearly show this difference in porosities. Safety Precautions for Rig Crew During Logging 1. Ensure that BOP is pressure tested above the expected surface pressure. 2. No welding job should be carried out during perforation job. 3. There should not be any fire /flame producing devices near cat walk. 4. Wireless set should be switched off, radio room must be locked. Even mobile phones are to be switched off. 5. Any high tension line (over/under ground) in the vicinity of the catwalk should be disconnected and ends should be insulated. 6. Pipe line with cathodic protection should be switched off. 7. Any rig electrical rig wiring which can make contact with the unit, cable or explosive device should be removed before perforation job. 8. A copy of electrical layout plan and communication network plan should be briefed to logging engineer. 9. Derrick floor, cat walk and unit parking place should be cleared for safe handling of explosive devices. 10. Logging unit parking place should be at a distance of thirty meter plus from the well head. 11. No unauthorized person should be allowed in the vicinity of thirty meters of working area. 12. No heavy equipment like crane, tractor should be allowed to operate in the drill site area while logging. 13. No movement of tubular should be done during logging. BOP must not be operated during logging. 14. Intimation of logging jobs involving explosives should be given 24 hours in advance to make proper arrangements. 15. Special care should be taken to avoid accidental firing of tool at the surface when a failed Tubing Conveyed Perforation tool is pulled out to the surface.

58

Bha Selection

CHAPTER - 7

BHA SELECTION The main consideration in BHA selection is to ensure that a specific pay zone is penetrated or drilled as per the plan. The restriction of total hole angle may solve some problems, but it is not a cure all. Even a typical 5° limit does not assure the well is free of troublesome doglegs. Mr. Lubinski pointed out that the rate of change in hole angle should be the main concern and not necessarily the maximum hole angle while selecting a particular BHA. The main objective should be to drill a useful hole with a full gauge, smooth bore and free of doglegs and key seats, offsets, spirals and ledges. Possible solutions to control deviations are; • Packed hole theory • Pendulum theory 7.1 PACKED HOLE THEORY In vertical drilling, packed hole assembly is used to overcome hole crookedness and to enhance ROP. Pendulum assembly is used only as corrective measure to reduce angle when maximum permissible deviation has been reached. 7.1.1 Packed Hole Design Factor 1. In vertical hole drilling, never use near bit stabilizer alone for drilling as it invariably causes angle build up. 2. Three or more stabilizing points are needed to form a packed hole assembly. Two points contact can follow a curved line. Addition of one more contact point will not follow a curved path and will maintain a straight path. 3. Stiffness of drill collars is another factor which play an important role in straight hole drilling. Stiffness is proportional to moment of inertia. If diameter of drill collar is doubled stiffness increases 16 times. Maximum permissible drill collar diameter in a given hole should preferably be used. 4. In hard formation, short blade length stabilizer and in soft formation, long blade length stabilizer is preferable. 7.1.2 Packed Hole Assembly Design Following are considered pertinent parameters for designing a packed hole BHA. 1. Crooked hole drilling tendencies (a) Mild crooked (b) Medium crooked (c) Severe crooked 2. Formation firmness (a) Hard to medium hard formations (b) Medium hard to soft formations 59


7.1.3 STABILIZING TOOLS The three basic types of stabilizing tools include the rotating blade, non-rotating rubber sleeve and the rolling cutter reamer. 1. Rotating Blade Stabilizer Use: It is most effective in soft to medium hard formations Long(soft formation) Straight blade Short (medium to hard formation) Rotating blade stabilizer Long (soft formation) Spiral blade Short (medium to hard formation) Types of rotating blade stabilizers: i.

Integral blade type (SR)

ii.

Welded blade construction (SR)

iii. Shrunk-on sleeve construction (SR) iv. Replaceable metal sleeve type (RR) v.

Replaceable wear pad type (RWP) (RR) • SR = Shop repairable • RR = Rig repairable

2. Non rotating rubber sleeve stabilizers (NRRS) Use: It is most effective in very hard formations such as lime and dolomite. The rubber sleeve is stationary and it acts like a drill bushing. It does not dig and damage the wall of the hole. It has got few limitations like: Limitation: • Bottom hole temperature < 250° F • It has got no reaming ability • Sleeve life is short in rough walls 3. Roller cutter reamers Use: These are used for reaming and added stabilization in hard formation. If any under gauge problems are encountered, roller cutter reamer should be used near the bit to overcome under gauging of the hole. 3-point reamer

( medium to hard formations)

Rolling cutter reamer 6-point reamer (hard to extreme hard formations)

60

Bha Selection

7.2 BOTTOM HOLE ASSEMBLIES 1. MILD CROOKED HOLE TENDENCIES (for medium hard to soft formations)

ZONE - 3

ZONE - 3

Vibration dampener

Vibration dampener

ZONE - 2

ZONE - 2

ZONE - 2

ZONE - 1

ZONE - 1

ZONE - 1

MILD

MEDIUM

ZONE - 3

Vibration dampener

SEVERE

The short drill collar size located between zone-1 and zone-2 is determined by hole size. Short drill collar length in ft = hole size in inches + / - 2 ft Zone - 1: Some type of long blade stabilizer directly above the bit Zone - 2: Blade stabilizer 30 feet above zone-1 Vibration dampener/Shock sub to be used at zone-2 above stabilizer in rough drilling conditions. Blade stabilizer 30 feet above zone-2 (in a medium size hole, like 8-1/2”) Zone- 3: Blade stabilizer 60 feet above zone-2 (in a larger size hole, 12-1/4” or larger) 2. MILD CROOKED HOLE TENDENCIES (for hard formations) Zone-1: Three point reamer directly above the bit Zone-2: Three point string reamer 30 feet above zoneVibration dampener/shock sub to be used at zone-2 above stabilizer in rough drilling conditions. Zone- 3 : Three point string reamer or a non-rotating rubber sleeve stabilizer (NRRS) 30 ft above zone-2 Note : Any stabilizers run above zone-3 would be used only to prevent the drill collars from buckling or becoming wall stuck and in most cases would have little effect on directing the bit. 61


3. MEDIUM CROOKED HOLE TENDENCIES (for soft to medium hard formations) One or two long blade stabilizers directly above the bit (for soft formation) Zone-1 Combination of a reamer and a blade stabilizer (for medium hard formation) a) For medium size and larger holes a 10-15 foot long, large diameter drill collar are required to be used between zone-1 and zone-2. b) for smaller holes less than 7” in diameter would require shorter drill collar not more than 6-8 ft long. The reason for this is to enhance stiffness. Two long blade stabilizers (for soft formation) Zone- 2 Combination of a reamer and a blade stabilizer (for medium hard formation) Vibration dampener/shock sub to be used at zone-2 above stabilizer in rough drilling conditions. a) For medium size (8-1/2”) and larger holes, a 30 ft long, large diameter drill collar would be used between zone-2 and zone-3. b) For smaller hole size 10-15 ft long, large diameter drill collar are required to be used between zone-2 and zone-3 One Long blade stabilizer (for soft formation) Zone- 3 String reamer or NRRS or blade stabilizer (for medium hard formation) A large diameter 30 ft long drill collar is required to be run between zone-3 and zone-4 Zone- 4 : The tools used in zone-4 can be the same type as tools used in zone-3 4. MEDIUM CROOKED HOLE TENDENCIES (for hard formations) Zone-1 : A 6-point reamer just above the bit Zone-2 : One string reamer Vibration dampener/shock sub to be used at zone-2 above string reamer in rough drilling conditions. Zone-3 : One string reamer or one NRRS stabilizer 5. SEVERE CROOKED HOLE TENDENCIES(for medium hard to soft formations) Three blade stabilizers directly above the bit (for soft formation) Zone-1 Combination of a reamer and blade stabilizer (for medium hard formation) a) For medium size and larger holes a 10-15 foot long, large diameter drill collar are required to be used between zone-1 and zone-2. b) For smaller holes less than 7” in diameter would require shorter drill collar not more than 6-8 ft long. The reason for this is to enhance stiffness. Two long blade stabilizers (for soft formation) Zone- 2 Combination of a reamer and a blade stabilizer (for medium hard formation) 62

Bha Selection

Vibration dampener/shock sub to be used at zone-2 above stabilizer in rough drilling conditions. a) For medium size (8-1/2”) and larger holes, a 10-15 ft long, large diameter drill collar would be used between zone-2 and zone-3. b) For smaller holes less than 7” in diameter would require shorter drill collar not more than 6-8ft long. The reason for this is to enhance stiffness. One Long blade stabilizer (for soft formation) Zone- 3 String reamer or NRRS or blade stabilizer (for medium hard formation) A large diameter 30 ft long drill collar is required to be run between zone-3 and zone-4 Zone- 4 : The tools used in zone-4 can be the same type as tools used in zone-3 7.3 BHA FOR DEVIATED HOLE 1. MOTOR KICK-OFF AND BUILD UP ASSEMBLY 1. Bit 2. Motor (preferably high speed ,low torque) 3. Float valve (shallow kick-off point only)\ 4. Bent sub 5. Orientation sub 6. Non-magnetic drill collar (monel) 7. Limited drill collar (1-2 stands) 8. 1 HW drill pipe stand 9. Drilling jar (over 500 m) 10. HW drill pipes (15 to 30 nos) 11. Drill pipes 2. ROTARY BUILD UP This assembly is run generally to finish build up initiated with motor and bent sub. The purpose of this standard build up assembly: i) To complete the build up before the straight hole section ii) To ream the hole prior to run stiff “hold” assembly. The build up assembly consists of: 1. Bit 2. Near bit stabilizer (spiral blades not too long) 3. One drill collar non-magnetic 4. D/C as required 5. One or two HW drill pipe stands. 6. One drilling jar 7. HW drill pipes 8. Drill pipes 63


3. HOLDING BHA 1. Bit 2. Stabilizer near bit (full gauge) 3. 9 m Monel 4. Stabilizer (full gauge) 5. Required drill collars 6. 1-2 HW drill pipe stands 7. Drilling jar 8. HW drill pipe stands 9. Drill pipes

64

Drill String

CHAPTER - 8

DRILL STRING The drillstring consists of Kelly, drill pipe, BHA etc. BHA consists of bit, reamer, jar, stabilizers, D/C and HW drill pipes etc. Drillstring Design depends on 1. Hole Size 2. Well Depth 3. Mud Weight 4. Margin of Over pull 5. Weight on bit 6. Well Trajectory 8.1 TRANSPORTATION Onshore 1. Thread protectors must be installed on both ends of pipe, prior to commencement of loading operations. 2. Load with either all the pin ends or all of the box ends of the tool joints to the same end of the truck. 3. Care should be taken to prevent chafing of tool joint shoulders on adjacent joints. Proper spacing practices should be observed to prevent chafing of drill pipe by hard banding on tool joints. 4. After load has been hauled a short distance, retighten load binding chains loosened as a result of load settling. Offshore 1. Pipe is to be placed on wooden stringers, which are spaced at approximately 10-foot intervals and shimmed to the same horizontal plane. 2. Wooden strips are placed so as to separate each layer of pipe; strips should be lined up on a vertical plane with the deck stringers. 3. Tubular should be secured to the deck or hull of the vessel by the use of load binding cables or chains attached at structurally adequate points. The boat captain according to expected sea conditions usually determines the number and size of such cable or chains. Properly sized steamboat ratchets or turnbuckles are used to maintain proper chain or cable tension. Each layer of pipe should be blocked. 8.2 STORAGE 1. Do not pile pipe directly on ground, rails, steel or concrete floors. The first tier of pipe should be about 12 inches above the ground to keep moisture and dirt away from pipe. 2. Pipe should rest on supports properly spaced to prevent bending of the pipe or damage to the threads. 3. Provide wooden strips as separators between successive layers of pipe so that no weight rests on the tool joint. Use at least three spacing strips. 65


4. Place spacing strips at right angles to pipe and directly above the lower strips and supports to prevent bending of the pipe. 5. While stacking drill pipes at the ground, the height of the stack should not be more than 10 feet. 8.3 HANDLING Drill Pipes 1. Drill pipes should be stacked in such a way at rig site that the box ends are facing the rig floor. 2. Remove rubber protectors (bettis) while storing drill pipes. Corrosion may form circumferential groove on pipe body if rubber protectors are left on. 3. Apply protective coating on pipe surface to prevent corrosion. 4. Thread protectors must be screwed on to both, box and pin ends of drill pipe while handling. 5. The pin and box threads should be lubricated with drill pipe thread compound before mounting the protectors. 6. Always use recommended thread compound (compound containing 40-60% finely powdered zinc by weight as recommended by API). 7. All drill pipes should be marked and recorded. Pin and box threads and shoulders of tool joints should be thoroughly cleaned before the joint is made up. 8. Threads must be free from foreign materials and must not be damaged . 9. Tool joint shoulder should be free from any cut mark or wash out. 10. If new drill pipes are to be used for first time, threads should be cleaned with suitable solvent and soft bristle brush. 11. The tool joint should be kept as close to the rotary slip as possible during make up or break out. 12. Always use both tongs while making up or breaking out drill pipes. 13. Always make up tool joints with appropriate recommended torque. 14. Down ward motion of the drill pipe must be stopped with the brakes and not the slips. 15. In every third trip working joints of drill pipe stands must be changed to facilitate the checking of non- working joint. 16. Set back area should be cleaned before stacking the drill pipe stands in fingers. 17. Mount thread protectors while laying down drill pipe on catwalk. 18. Threads and shoulders of the box and pin of a dry connection should be carefully checked. 19. Do not use specially made API modified compound for casing and tubing on drill pipe tool joints. 20. Check for any notch (i.e. slip mark, spinning chain marks, tong marks and cuts etc.) on pipe body. If any circumferential or transverse notch is found on pipe body, do not use the drill pipe. 21. Check for any longitudinal cracks on tool joint body because of heat cracking. Do not use the drill pipe if such parallel longitudinal cracks are present. 22. Do not thin, thread compound for ease of application. 23. Do not allow the pin end to strike the box shoulder while tagging. 24. Do not spin pipe too fast. If joint wobbles and bends, high speed can burn threads. 66

Drill String

25. Do not use tongs on pipe body. 26. Do not use rotary for making up and breaking out drill pipes. 27. Do not let the slips ride the pipe, this may damage the slips and may create other complications. 28. Do not use slips designed for one specific size of pipe on any other size of pipe. 29. Do not use wrench or other sharp edged tool to jack drill pipe stand in position on set back platform. Drill Collars 1. Thread protectors should be used and screwed fully on both pin and box ends when handling drill collars. 2. Use cast steel protectors on pin and box end of drill collars while picking up from catwalk to derrick floor. 3. Check that slips and elevator for handling the drill collars are of proper size. 4. A safety clamp should be invariably used while making up or breaking drill collars which do not have slip and elevator recess (i.e. non magnetic drill collar etc.) 5. Before make up, clean the threads thoroughly. Check for any burrs or damage and lubricate properly. 6. Always use a good thread compound. Thread compound should contain 60% finely powdered metallic lead. 7. If lift subs are used, its pin threads should be cleaned, checked and lubricated on each trip. 8. A new joint should be carefully lubricated, made up, broke out, relubricated and made up again on initial make up. 9. Always use chain tong for initial tightening of drill collars. 10. A torque gauge should be used on tong line to measure the make up torque. 11. On every third trip, change the working joints of drill collars. 12. Make close visual inspection of every non-working joint while pulling out. 13. Avoid rotary for making up or breaking out of drill collar connection. 14. Do not over torque or under torque a drill collar connection during make up. Insufficient torque or too much torque both may cause problems. 15. Do not jerk the line while making up D/C. Kelly 1. 2. 3. 4. 5. 6.

Always use new drive bushing roller assemblies with new Kelly. The rollers of drive bushing assemblies must be adjusted for minimum clearance, if possible. Drive assemblies should be replaced periodically to ensure minimum clearance from wear. Always use Kelly saver sub. It protects the lower pin thread of Kelly from excessive wear. Lubricate the drive surfaces so that Kelly slides freely through the drive bushings. Visual inspection at regular intervals should be made to check the wear of drive bushings and Kelly corners. 7. Do not move or transport Kelly without scabbard. It provides the support to limber Kelly. 8. Do not use bend or crooked Kelly as it results in rapid wear of Kelly and drive rollers. 9. Do not weld on the drive corners of Kelly for rebuilding the worn Kelly.

67


8.4 VISUAL EXAMINATION WHILE TRIPPING 1. Look for dry or muddy threads, check for wash out, galling and worn threads. 2. When galling is observed, check for proper thread compound, torque, and adequate shoulder areas. 3. Check for wear on tool joints and drill pipe. If eccentric tool joint wear is noticed, check pipe for straightness. 4. Watch for undercutting of the tool joint in the area of the 18-degree elevator shoulder. Undercutting may be more prevalent on tool joints without hard metal bands. 5. Watch tool joints while tripping for evidence of pin stretch and box swelling due to overtorquing. Over-torquing frequently occurs down hole while drilling. 6. Watch for washouts in drill pipe in the connection area of the joint, in the slip area and in the transition between the upset and the pipe nominal wall. 7. Watch for dents, slip cuts and other similar damage. These areas are potential points for failures to originate which are thoroughly investigated and checked out before running in the hole. 8.5 FIELD INSPECTION OF DRILL COLLARS 1. Drill collar inspection should be more than just looking for cracks. Thread profile should be checked with a profile gauge to detect stretched pins and worn threads. 2. Boxes should be checked for swelling and shoulders should be inspected for leaks or conditions that may cause leaks. 3. Minor repairs can be performed in the field to keep the collars running. Shoulders can be polished with refacing tools if the damage is not too severe. 4. Fins, burrs and small galls can be removed with a small grinder or file. 8.6 H2S EXPOSURE H2S forms weak acids with water that attacks the drill string material. Maintain higher pH above 10.5 in the mud system. 8.7 FATIGUE FAILURE Following points needs to be taken care to avoid fatigue failure of drill string. 1. Running drill pipe in compression 2. Too much change in cross-sectional area 3. Crooked drill pipe 4. Drilling through dog-leg 8.8 ALUMINIMUM DRILL PIPE 8.8.1 Care and Handling 1. The typical Brinell hardness of aluminum drill pipe is 135 while grade E-75 steel is approximately 200 BHN. Careless handling can mark both tubes. Aluminum is more easily marked because it is softer. 2. Drill String with aluminum drill pipe should be transported on a float bed truck with minimum three supporting spacers on each layer. 68

Drill String

3. Loading and unloading drill string should be controlled and quiet. 4. Avoid hooks in handling the drill string. Choker slings with not less than 10' separation on a strong back or spacer bar are recommended. 5. Aluminum drill pipe is likely to show more wear and/or erosion when drilling formations that are hard and abrasive. The nicks and gouges that appear in aluminum pipe rarely lead to fatigue problems unless the marks are very deep. 6. Always use two tongs to make and break connections. 7. Slip dies for aluminum pipe are modified for minimum penetration and maximum power. Slips should never be used to stop the downward motion of drill string, whether the pipe is aluminum or steel. 8. Slips should be set close to rotary table for making up and breaking out. This will minimize pipe bending during these operations. 9. BOP: In case of external upset aluminum drill pipe, the OD of the pipe is slightly larger than steel pipe of the same nominal size. If rams for steel pipe are used on aluminum, the aluminum pipe is likely to be damaged severely. To avoid this, use proper size of Ram Block. 10. Always use elevators with cylindrical “bores which will clear these DTE DPE diameters. 11. It is recommended that drill string with aluminum drill pipe be plastic coated internally. This should be replaced as necessary during the string life. Plastic coating improves hydraulics and reduces the erosive or corrosive effects of drilling fluids. 12. Straighten Aluminum Drill Pipe if it is bent. 13. Slightly bowed pipe tends to straighten under the stretching effect of the drill collar load in a normal drilling operation. 14. Drill String Operating Limits: The modulus of elasticity of aluminum is 10.6 x 106 compared with 29 x 106 for steel. Aluminum has much greater flexibility and requires about twice as many turns to reach the same torque level. 15. The stretch of aluminum is greater in air or in mud lighter than 12 pounds per gallon (ppg). When the mud weigh is more than 12 ppg, the stretch of aluminum is less than steel. Calculate the stretch of aluminum carefully when pulling stuck drill string, setting a liner or when steel pipe is below aluminum. Also calculate carefully to determine the additional turns necessary to achieve the equivalent torque in these and other operations. 16. The flexibility of aluminum drill pipe gives it excellent fatigue resistance. Thus, aluminum drill pipe can be most useful when operating in crooked hole areas, extended reach wells or horizontal completions, or in all those cases where pipe is subjected to severe bending during rotation. 17. While using mixed strings of aluminum and steel, aluminum string should not be less than 5% of the total string and this minimum amount should be added at one time. 18. Use aluminum pipe in the upper section of the string but care should be taken to keep loading within recommended limits. 19. The consistent lengths of aluminum drill pipe offer greater accuracy when using free point indicators, placing back off shots or other instruments, checking pipe tallies and determining if pipe has been stretched. 20. Care should be taken that tensile yield is not exceeded by measuring mid-length pipe diameters frequently.

69


8.8.2 Fishing of Stuck Aluminium Drill Pipe The general procedure in fishing of stuck aluminum drill pipe is similar to those for steel with these exceptions: • Electro-mechanical free point indicators are necessary because of aluminum’s non-magnetic quality. • The OD of external upset aluminum drill pipe is larger than the equivalent size steel pipe. Also longer taper at each end means that overshot assemblies must be long enough to fit over the fish. Standard overshots with a 3 or 4-foot extension or a joint long enough to reach over the next tool joint are normally satisfactory. • The spring back energy of aluminum pipe is greater than steel. On a heavy pull, safety precautions should be exercised to prevent injury to personnel. • If circulation is lost, or fish is without circulation when temperature is above 300 °F, high torsional and/or tensile load should be avoided until pipe temperature is reduced.

70

Wire Rope

CHAPTER- 9

WIRE ROPE 9.1 NOMENCLATURE The wire rope is made of number of strands laid helically around a core. Wire rope is the combination of wires, strands, and core. Wire rope consists of strands laid around a main fibre or steel core. The multi wire strands that are helically laid around the core are of two types i.e. flattened strand & round strand. In case of flattened strand, the no. of wires in each layer of strand is described. In round strand the make up is named as Seale, Filler, Warrington. The wire rope is spooled on the drum of the draw works, reeved on the crown block and traveling block and is used for drilling operation. Example Where 1“ 5000’ 6 19 S PRY RRL IMPS IWRC

-

-

1” X 5000’, 6 X19 S PRY RRL IMPS IWRC

Diameter of line in inches Length of line in feet Number of strands per line Number of wires per strand Seale pattern Pre formed strands Right Regular Lay Improved plow steel Independent Wire Rope Core

RIGHT LAY REGULAR LAY

LEFT LAY REGULAR LAY

RIGHT LAY LANG LAY

LEFT LAY LANG LAY

9.2 SELECTION CRITERIA Wire line selection depends on work to be carried out which in turn decides the size and type of line to be used. Choose and follow a cutoff program, which suits the condition. Proper care should be taken to increase the service obtained from the line. Compute and record the service performed in Ton Miles by the line. 9.3 CLASSIFICATION Regular Lay The wires are laid in one direction and the strands in other so that the visible wires appear running parallel to the rope axis.

71


Lang’s Lay In Lang’s lay the wires and strands are laid in the same direction so that the visible wires run at an angle of about 30 degree to the rope axis. Direction of Lay The direction of lay or rotation of the strands is normally right hand but the wire ropes also are of left hand lay. 9.4 DIFFERENT TYPE & SIZES OF WIRE ROPE SN

SERVICE & WELL DEPTH

SIZE, INCHES

ROPE DESCRIPTION

1.

Rod & Tubing Pull Lines Shallow Intermediate Deep

1/2 to 3/4 inch 3/4, 7/8 7/8 to 1-1/8 inch.

6 x 25 FW or 6 x 26 WS or 6 X 31 WS RRL or LRL, IPS or EIP, IWRC

Sand Line Shallow Intermediate Deep

1/4 to 1/2 inch 1 /2* to 9/16 9/16 to 5/8

6 X 7 Bright or Galv. , RRL or IPS, FC

Drilling lines–Cable Tool Shallow Intermediate Deep

5 / 8, 3/ 4 3 / 4, 7 / 8 7 / 8, 1

6 X 21 FW, RRL or LRL, PS or IPS, FC

Casing Lines-Cable Tool Shallow Intermediate Deep

3 / 4, 7 / 8 7 / 8, 1 1, 1–1/8

6X25FW,RRL,IPS,FC or IWRC 6X25FW,RRL,IPS or EIP,IWRC

Drilling Lines- Rotary Rigs Coring & Slim HoleShallow Intermediate

7 / 8, 1 1, 1–1/8

6X26,WS, RRL, IPS or EIP, IWRC 6X19 S or 6X26 WS, RRL, IPS or EIP, IWRC

Drilling lines-large rotary rigs Shallow Deep

1, 1- 1 / 8 1-1 / 4 to 2 inch.

6 X 19 S or 6 X 21 S or 6X25 FW, RRL, IPS or EIP, IWRC

7.

Winch Line-Heavy Duty

5/8 to 7/8 inch.

6X26WS or 6X31WS, RRL, IPS or EIP, IWRC

8.

Offshore Anchorage Line

7/8 to 1-1/8 inch. 7/8 to 2-3/4 inch.

6X36 WS,PF,RRL,IPS or EIP, IWRC 6X19 class, Bright or Galv., RRL, IPS or EIP, IWRC 6X37 class, Bright or Galv., RRL, IPS or EIP, IWRC 6X61 class, Bright or Galv., RRL, IPS or EIP, IWRC

2.

3.

4.

5.

6.

1-3/8 to 4-3/4 in. 3-3/4 to 4-3/4 in.

72

Wire Rope

9.

Mast Raising Lines or Bull line

10.

Guideline Tensioner Line Riser Tensioner Lines

1–3 /8 and smaller 6X19 class, RRL , IPS or EIP, IWRC 1-1/2 and larger 6X37 class, RRL , IPS or EIP, IWRC 3/4 1-1/2 , 2

6X25 FW, RRL, IPS or EIP, IWRC11. 6X36 WS or 6 X 41 WS or 6X41 SFW or 6X49 SWS, RRL , IPS or EIP, IWRC

9.5 CARE & MAINTENANCE 9.5.1 Handling the Reel 1. Always use wooden blocks between the wire rope and the sling to prevent damage to the wire or distortion of the strands of the rope while lifting. 2. Bars for moving the reel should be used against the reel flange, and not against the rope. 3. Never roll over or drop reel on any hard, sharp object. 4. Never drop the reel from a truck or platform while unloading. 5. Do not allow the wire rope to come in contact with mud, dirt, or any other medium,harmful to steel to protect it against damage. 6. Store wire rope in properly lubricated condition to minimize the effects of corrosion on wire rope, as it reduces the strength of wire rope. 7. Never use wire rope in an arc welding circuit as it damages the line. While using a torch near the wire rope, always protect the rope from the flame and sparks. 9.5.2 Handling During Installation 1. Blocks should be strung to give a minimum of wear against the sides of sheave grooves. 2. It is good practice to suspend the traveling block from the crown block on a single line while changing lines as it tends to limit the amount of rubbing on guards or spacers, as well as chances for kinks. This practice is also very effective in pull through and cut–off procedure. 3. Set the reel on a substantial horizontal axis so that it is free to rotate as the rope is pulled of and in such a position ensure that it is not rubbing against derrick members or other obstructions while being pulled over the crown. 4. The reel should be jacked off the floor and hold by using suitable fixture so that it can turn on its axis freely. 5. While winding the wire rope on the drum, sufficient tension should be kept on the rope to assure tight and even spooling. 6. When a worn rope is to be replaced with a new one, the use of a swivel type-stringing grip for attaching the new rope to the old rope is recommended. The new rope should not be welded to the old rope to pull it through the system. 7. Do not allow the wire rope to kink when spooling or un-spooling. Use a wooden block between the hammer and rope while hammering for crowding the wraps and operation should be carried out with great care. Never strike the wire rope with hammer or crow bar; it may cause kinks or bruises. If a rope becomes covered with dirt or grit clean it with a brush.

73


8. After properly securing the wire rope in the drum socket, the number of excess or dead wraps or turns specified by the equipment manufacturer should be maintained. 9. Whenever possible, a new wire line should be run under controlled loads and speeds for a short period after installation as it will help to adjust the rope to working condition. 10. If a new coring or swabbing line is excessively wavy when first installed, two to four sinker bars may be added on the first few trips to straighten the line 11. Ensure that clamps used for fastening the rope to dead end do not kink, flatten or crush the rope. 9.6 REEVING PROCEDURE 1. Attach the traveling block to the hang line or otherwise support in a vertical position. The best position is where the elevators are in pick-up position near the rotary table. 2. Provide a permanent location for the reel of drilling line near the deadline anchor. The reel should be firmly supported on its horizontal axis with the line unwinding from beneath the reel drum (not from the top of the drum). 3. When leading the line from the reel to the first crown sheave, use snatch blocks with large diameter sheaves to guide the line and keep it from rubbing on derrick members and other obstructions. 4. Break the reel flanges so that the rope does not become loose on the reel while being unwound, and so an even tension is applied on the rope between the blocks, do not apply the brake on the rope itself. 5. The rope should be spooled under a sufficient load to ensure tight spooling. 6. To start stringing the rope. Remove the old rope from the dead line anchor and fasten it to the new rope with a swivel grip. 7. Care should be taken to see that the grip is properly applied. 8. Wind all the old rope on the draw works drum and pull enough of the new rope through to permit attaching to the drum. 9. Keep as much back tension in the rope as possible, because slackness can cause loops and/or kinks to form. 10. Fasten the new line so that it will not run back through the blocks. Remove the swivel grip. Take the old line off the drum and transfer it to a storage reel. 11. Attach the new line to the draw works drum and provide enough wraps so that the proper number will be on the drum at the pick-up point. 12. When the traveling block is at the lower pick-up point, 6- 9 wraps should be on the drum (if grooved). Plain-faced drums must have a full layer of line plus 4-6 wraps on the second layer as needed. 13. Hold down sheaves is the best way to anchor the line when cut-off practices are to be employed. The line should go around the hold-down sheaves in the same direction as it comes over the deadline sheave and from the storage reel. 14. Always anchor the dead end of the line properly without damaging the wire as it can cause kink in line. 15. After anchoring the deadline end, raise the traveling block and take off the supporting line. The block, hook and elevators may then be lowered through the V-door far enough to unreel the line on the drum, so that it can be re-reeled tightly. 16. Reeve the line. 74

Wire Rope

9.7 DESIGN FACTOR Design Factor = B/W Where : B = Nominal catalog strength of the wire rope, pounds W = Fast line Tension / load, pounds Take care when a wire rope is operated close to its Minimum Design Factor ( MDF), Consider minimum design factor for successful field operations as follows; • Cable-tool line 3 • Sand line 3 • Rotary drilling line 3 • Hoisting service other than rotary drilling 3 • Rotary drilling line when setting casing 2 • Pulling on stuck pipe or infrequent operations 2 • Mast raising and lowering 2.5 Note: Wire rope life varies with the design factor. Therefore longer rope life can generally be expected when relatively high design factors are maintained. 9.8 CARE OF WIRE ROPE 1. Sudden, severe stresses are injurious to wire rope and such applications should be reduced

2. 3. 4. 5.

6. 7.

8.

9.

10.

to the minimum. A jerk line may be rigged and clamped to the drilling line when it is necessary to do considerable jarring in one place. As wear increases with speed; moderately increasing the load and diminishing the speed can achieve best results. Excessive speeds of the block may injure wire rope. For most drums a maximum rope speed of 40 ft/min rope travel for hoisting or lowering is recommended. Line whip and natural vibrations also cause fast line fatigue; therefore, a wire line stabilizer must be installed on fast line. Vibration causes drilling line fatigue and shortens life. Failure due to vibration is most serious at the deadline (crown block) sheave. Stabilizers should be used to avoid whipping of the fast line. All sheaves should be in proper alignment. The fast sheave should line up with the center of the hoisting drum. Sheave grooves should be checked periodically with the gauge for worn sheaves and dimensions. The sheave grooves should have a diameter of not less than that of the gauge otherwise a reduction in rope life can be expected. Each operator should establish the most economical point at which sheaves should be re-grooved by considering the loss in rope life, which results from worn sheaves as compared to the cost involved in re grooving. Wire line must be periodically examined. A proper slip and cut- off practice should be followed after evaluating the work done by a rope. A record of work done in ton – mileage should be maintained Use only drop forged clamps of U-bolt type. 75


11. Dead anchor should be equipped with a drum and strong clamping device to withstand the wire rope loading. Diameter of anchor drum or sheave should be minimum 12 times the normal rope diameter. 12. All sheaves should be properly lubricated to ensure minimum turning efforts. 13. Wire rope should be securely seized on each side of the cut before cutting the rope. It will prevent the rope from untwisting. 14. Do not subject the wire rope to severe stresses due to impact and shock loading. 15. If rope is operated with heavy loads or if the metal is too soft, scouring or corrugation of drums and sheaves will occur. Repair the drums if corrugated impressions are made by wire line. 9.9 FLEET ANGLE When a wire rope is led from the drum onto the fast sheave, it is parallel to the sheave groove only when at one point on the drum, usually the center. As the rope departs from this point either way, an angle is created which starts wear on the side of the rope. This angle is called the fleet angle. The fleet angle although necessary, should be held to a minimum. Experience indicates that it should be held to less than 1-1/2 degrees for smooth faced drums and to less than 2 degrees for grooved drums. Poor fleet angles cannot only cause excessive abrasive wear, but also build-up excessive torque in a rope. a. For smooth faced drums, the maximum angle

=

1.5 degrees.

b. For grooved drums, the maximum angle

=

2.0 degrees.

c. The minimum angle should be at least

=

0.5 degrees.

9.10 SPOOLING •

•

•

It is most important to get the first drum layer full and tight without over crowding so that it will support the succeeding layers. That is to say the first layer acts as a sort of a “grooving” for following layers. One way to assist proper drum winding is by means of a riser strip or wedge on the dead end side. Turn-back rollers or kick plates prevent piling up of wraps at the flange. Wear due to crossover points cannot be completely avoided. It can be reduced by controlled spooling, which is provided by grooved drums. In any type of spooling there must necessarily be two crossover points with each wrap. As a lower layer proceeds in one direction across the spool, the next layer must proceed in the other direction. Two ropes are crossed over in each drum revolution. An improvement in spooling methods is the controlled crossover system. This is a grooving system where the crossover points are controlled thereby reducing wear and vibration.Instead of being a helical shape like a coiled spring, most of the grooves are parallel to the drum flanges. Normally at the crossover points, pitch changes rapidly where the line is crossed from one groove to the next. In controlled spooling the change in pitch is less severe. In controlled pyramid spooling wear and cutting-in is parallel and there is no tendency for the line to slip over.

76

Wire Rope

9.11 ATTACHMENT OF CLAMPS ON WIRE ROPE Procedure When using U-bolt clips, care must be exercised to make sure that they are attached correctly, i.e. the U-bolt must be applied in such a way that the “U” section is in contact with the dead end of the rope (Figure 1-3) as per the following steps. Turn back the specified amount of rope from the thimble. Apply the first clip one base width from the dead end of the wire rope (U-bolt over the dead end, the live end rests in the clip saddle). Tighten nuts evenly to the recommended torque. 1. Apply the next clip as near the loop as possible. Turn on nuts firmly but do not tighten. 2. Space additional clips if required equally between the first two. Turn on nuts, take up rope slack, and tighten all nuts evenly on all clips to the recommended torque. 3. Apply the initial load and retighten nuts to the recommended torque. Rope will stretch and be reduced in diameter when loads are applied. Inspect periodically and retighten to the recommended torque. 4. Add one additional clip if a pulley is used in place of a thimble for turning back the rope. 5. The number of clips shown is based upon using right regular lay, or right Lang lay wire rope, 6 x 19 class or 6 x 36 class, fiber core or IWRC, IPS or EIP. If Seale construction or similar large outer wire type construction in the 6 x 19 class is to be used for sizes 1 inch and larger, then add one additional clip. 6. For other classes of wire rope not in this list, it may be necessary to add additional clips to the number shown. If a greater number of clips are used than shown in the table, then the amount of rope turn back should be increased proportionately. 7. Failure to make a termination in accordance with aforementioned instructions, or failure to periodically check and retighten to the recommended torque, will cause a reduction in efficiency rating.

NEVER PLACE “U-BOLT” OVER THE LIVE LINE ALL THREE BOLTS ARE ON THE LIVE LINE

U-BOLTS ARE STAGGARED, ONE CLIP IS ON THE LIVE LINE

Fig. 1. Crosby Wire Rope Clips

INCORRECT SPLICING OF TWO WIRE ROPES, UNBOLT ARE ON LIVE LINE

Fig. 2 Incorrect Method to Attach Clips to Wire Rope

Fig. 3. Correct Method to Attach Clips to Wire Rope

The correct way to attach U-bolts is shown at the top; the “U” section is in contact with the rope’s dead end and is clear of the thimble. 77


NUMBER OF CLIPS FOR DIFFERENT WIRE ROPE SIZES WIRE ROPE DIAMETER,

NO. OF CLIPS

INCHES

LENGTH OF ROPE TURNED BACK

TORQUE

INCH

MM

Frt.

N.M

1/8

2

3 –1/ 4

83

4.5

6.1

3 / 16

2

3-3/4

95

7.5

10

1/4

2

4-3/4

121

15

20

5 / 16

2

5-1/4

133

30

41

3/8

2

6-1/2

165

45

61

7 / 16

2

7

178

65

88

1/2

3

11-1/2

292

65

88

9 / 16

3

12

305

95

129

5/8

3

12

305

95

129

3/4

4

18

457

130

176

7/8

4

19

483

225

305

1

5

26

660

225

305

1–1/8

6

34

864

225

305

1- 1 / 4

7

44

1117

360

488

1- 3 / 8

7

44

1120

360

488

1–1/2

8

54

1372

360

488

1–5/8

8

58

1473

430

583

1–3/4

8

61

1549

590

800

2

8

71

1800

750

1020

2–1/4

8

73

1850

750

1020

2–1/2

9

84

2130

750

1020

2–3/4

10

100

2540

750

1020

3

10

106

2690

1200

1630

9.12 EVALUATION OF ROTARY DRILLING LINE The factors affect the life of wire rope, 1. Mast/derrick height, crown blocks sheaves, traveling block sheaves, draw works drum Type of string-up - 6, 8, 10 or 12 lines 2. Dead line anchor or clamp, wire line stabilizer and turn-back rollers 3. Experience of crew, depth of well & drilling conditions 4. Size and number of drill pipe & drill collars 5. Drill stem tests, coring, stuck pipe,” twist offs” and “fishing” jobs 6. Setting casing, fleet angle 78

Wire Rope

TON- MILE CALCULATION • Heavy wear would occur in a few localized sections where the rope makes contactwith the traveling block sheaves, and where the rope makes contact with the crown block sheaves when the slips are pulled going in or coming out of the hole, and on the drum where each wrap of rope crosses over the rope on the layer below. Broken wires at these points of critical wear would result in the retirement of the entire string up, even though the remainder of the rope is in good condition. • Do not cut too much wire rope frequently, there will be an obvious waste of usable drilling line, which will result in higher than necessary rig operating costs. However, if the rope is moved through the reeving system too slowly, sooner or later some section of the drilling line will become worn and damaged to such an extent that there will be a danger of failure, injury to personnel, damage to equipment and expensive downtime. At the very least, it will be necessary to make a “long cut” to eliminate some broken wires. • For these reasons, it is important that the drilling line be cut at the proper rate. The purpose of this simplified cut-off practice is to give the drilling crew a method for keeping track of the amount of work done by the drilling line, and a systematic procedure for making cuts of the appropriate length at the appropriate time. The objective is to obtain maximum rope service without jeopardizing the safety of the rig operation. • In conjunction with the record keeping required for the cut-off procedure, daily visual inspection of the drilling line should be made for broken wires and any other rope damage. It must be remembered that in all cases, visual inspection of the wire rope by the drilling crew must take precedence over any pre-determined calculations. • The only complicated part of a cut-off procedure is the determination of how much work has been done by the wire rope. Methods such as counting the number of wells drilled or keeping track of days between cuts are not accurate because the load changes with depth and with different drilling conditions. The various operations performed (drilling, coring, fishing, setting casing, etc.) subject the rope to different amounts of wear. • For an accurate record of the amount of work done by a drilling line, it is necessary to calculate the weight being lifted and the distance it is raised and lowered. In engineering terms, work is measured in foot-pounds. On a drilling rig the loads and distances are so great that we use “ton-miles.” One ton-mile equals 10,560,000 foot-pounds, and is equivalent to lifting 2,000 pounds a distance of 5,280 feet. • Use the Ton-mile indicator. FORMULA FOR WORK DONE: Total work done by line during trip is equal to;

⎛ C⎞ D(Ls + D) Wm + 4D ⎜ M + 2 ⎟ ⎝ ⎠ T = 5280 x 2000 where; D Ls N Wm

= = = =

Depth of the hole in meter ft, Length of drill pipe stand, meter ft Number of stands of drill pipe, Effective weight of drill pipe lb/ft. 79


M C T

= Total weight of traveling block assembly lb = Effective weight of drill collar minus the effective weight of same length of drill pipe lb = Ton miles

Note : For round trip work done will be twice of the calculated above. 9.13 CUT-OFF PROGRAM So long as the maximum ton-mile accumulation shown on the program is not exceeded, a cut may be made whenever it is convenient. It is only necessary to total the ton-miles accumulated since the last cut and divide by 19.0 to determine what length to cut. This way the ton-miles per foot cut will always be exactly 19.0, and the wear on the drilling line will be uniformly spread along its length. 1. Work done can be calculated by the following method. During slip and cut operations the travelling equipment (block and hook) will be properly secured with hanging off pendants so that inadvertent movement is not possible. Slip & cut programs should be continually evaluated to maximize efficiency and minimize waste. 2. Whatever program is used, it should be followed throughout the life of one entire drilling line. If no long cuts are required, and it is believed that more service can be obtained from a line, the goal can be raised one ton-mile per foot cut. This procedure should be followed until the optimum goal is found. 3. Daily visual inspection of the drilling line should be made for broken wires and any other rope damage. 4. Avoid accumulating more ton-miles between cuts than the maximum shown on the program for your rig even on the first cut of a new line. 5. It is best not to run up to the maximum permitted ton-miles each time between making a cut, as some problem on your rig could prevent a cut being made at the proper time and lead to a ton-mile over run. A better approach is to bounce around on your program, cutting with a new ton-mile accumulation sometimes and alternating with a medium or higher ton-mile accumulations. This practice does not waste wire rope because you are always cutting off lengths in proportion to the work accumulated. 6. Accurate measurement of the length to cut is very important. A steel tape should be used when making this measurement. 7. When stringing back from 12 to 10 lines, or from 10 to 8 lines, make a cut of the appropriate length based upon the ton-mile accumulation at that time. This procedure will shift the critical wear points on the rope during heavy operations such as casing lowering. 8. Keep your wire rope history sheets accurate and complete. 9. Calculate ton-miles during drilling after each round trip. Failure to record Ton-miles during drilling is probably the most common mistake made in cut-off practice. 10. The best cut-off program is the one with the most consistent ton-mile per foot cut values. By staying as close as possible to the Ton-mile goal you will avoid long cuts and maintain the safest and most economical use of drilling line. 11. No. of slips between cut offs can vary considerably depending upon drilling conditions and on the length and frequency of cut offs.

80

Wire Rope

9.14 CUT-OFF PRACTICE FOR DRILLING LINE Cumulative work before first Cut- off Work done by a wire line in Ton -miles with respect to height of mast & diameter of wire line for the first cut can be obtained as: Derrick or Mast

Formation Hardness Height (ft)

Total work of drilling line before the first cut off 1”

1 1/8”

1 1/4”

1 3/8”

1 1/2”

Ton miles

Ton miles

Ton miles

Ton miles

Ton miles

80-87

Very hard Hard Medium Soft

500 500 500 600

94-100


500 500 500 600

126-131

Very hard Hard Medium

600 700 800

1000 1100 1200

Soft

900

1300

133-138


600 700 800 900

1000 1100 1200 1300

142-147


187-189


600 700 800 900

1000 1100 1200 1300

1600 1800 2000 2100 1600 1800 2000 2100

2000 2200 2400 2600

Note: All the ton-miles in the table have been calculated using a safety factor of 5.Every body is aware of that this safety factor often falls consistently below 5 CALCULATION OF WORK DONE Height of mast: 138 ft, wire rope diameter: 1 ¼”, drum diameter: 28 inches, safety factor: 3 Say you are operating at a safety factor of 4 then total work done found in the table must be multiplied by 0.8. Ans: For S.F.= 5, the total work done is 1100 T-miles. For S.F = 3 curve (fig. 4a,b below) gives the corrective fig: = 0.58 Then the total work done is = 1100 x .58 .i.e. 638 T-miles 81

Drilling Operation Practices Manual 1.5 10

9

8 1.0

7

TON MILE SERVICE FACTOR

6 5

0.5 4

3

2

Based on cutoff program indicated in Fig. 2000

3000

4000

5000

6000

0

1

2

3

5

6

7

DESIGN FACTOR

RELATIONSHIP BETWEEN ROTATRY LINE INITIAL LENGTH AND SERVICE LIFE

Fig. 4b:

Fig. 4a:

2.

4

7000

RECOMMENDED CUT OFF LENGTHS FOR ROTARY DRILLING LINES Drim diameter (inch) MAST HEIGHT (ft)

11

12

14

16

18

20

22

24

26

28

30

32

34

36

34.6 15½ (1)

34.7 14½

34.5 13½

33.9 12½

33 11½

No. ofofwraps Cut off length in meters and number drum per lapscut-off (1) 187

142-143 -147 133-136 -138 126-129 -131

25.7 11½

27.5 11½

26.8 10½ 24.3 9½

24.7 15½

25.5 14½

23.9 12½

23.9 11½

25.7 11½

25.1 10½

22.7 24.3 9½ 9 ½

22.3 15½

23.1 14½

21.9 12½

23.9 12½

23.9 11½

23.5 10½

18.4 11½

18.4 10½

18.2 9½

19.7 9½

19.0 8½

20.2 19½

19.6 17½

18.5 14½

18 12½

87

18.2 17½

19.7 14½

19.0 12½

16.5 11½

11.0 12½

25.9 12½

22.3 17½

94-96 -100

66

25.9 13½

12.0 11½

(1) In order to change the point of cross over on the drum, where wear and crushing are most sever, the laps to be cut are given in multiples of one-half lap.

Note: Cut off length in metre is mentioned in bold letters in top line whereas no of wraps to cut off is given below the cut off length. 82

Wire Rope

9.15 PRECAUTIONS WHILE USING WIRE ROPE 1. Avoid developing of kink caused by pulling down a loop in a slack line during improper handling. Early rope failure will undoubtedly occur at this point. 2. Avoid bird caging caused by sudden release of tension and resultant rebound of rope from over loaded condition. 3. Inspect localized wear over an equalizing sheave carefully because it is not visible during operations of wire rope. 4. Avoid ‘strand nicking’ which is caused by adjacent strand rubbing against on another and is usually caused by core failure due to continued operation of rope under high tension. In this individual wire rope breaks in the valleys of the strands. 5. Avoid fatigue failure of wire rope subjected to heavy loads over small sheaves. 6. Avoid fatigue break in a cable tool drill line caused by a tight kink developed in the during operation. 7. Wire line tolerances are given below in table; Nominal dia of rope, inch 0 to 3/4

Undersize, inch

Oversize, inch

0

1/32

1-3/16 to 1-1/8

0

3/64

1-3/16 to 1-1/2

0

1/16

Place sheave gauges in grooves as shown (Fig. 5) Detail “A” reflects gauge fit in a sheave. Detail “B” reflects gauge “fit” in a worn (tight groove) sheave. Detail “C” reflects gauge “fit” in a sheave where the groove is too large. Sheave grooves in the crown and traveling blocks should be checked at the time of installation a new line. Sheave grooves must neither be too small nor too large to avoid damage to the line. Small grooves cause pinching and over heating, large grooves allow flattening of the line. Detail B Groove Too Small

Detail A Detail C Correct Size Groove Groove Too Wide

Fig. 5. Grooves too small, just right, and too big

83


9.16 ATTACHING LINE AND SHEAVE DIAMETERS Bending of the drilling line over sheaves reduces the amount of load it can carry. For the bending itself puts a load on the line. Hence diameter of the sheave should be big enough for drilling line. When wire rope is used over sheaves that are too small its service life is reduced. Bending causes readjustment of the positions of the wires and strands as well as bending of the wires themselves. Such re-adjustment, which must occur continuously in the multiple –line reeving system, causes fatigue. Wires in drilling line will break by continuously bending it backward and forward. To minimize the fatigue of the drilling line due to bending sheave diameters should be with in the following limits; Table No…. Rope diameter, inch

Sheave diameter, inches Recommended (6 X19)

Mini (6 X 19)

7/8

39

26

1

45

30

1-1/8

50

34

1-1/4

56

38

1-3/8

62

41

1-1/2

67

45

84

Well Head Fitting

CHAPTER -10

WELL HEAD FITTING After WOC, casing head housing which is the first well head component to be installed is fitted on the surface casing. Casing head housing serves as a connector from the surface casing to the BOP stack during drilling and then to other subsequent well head components. It has a bowl to accept a casing hanger to suspend the intermediate casing. The following procedure is adopted. 1. Remove false conductor / Riser. 2. Cut the surface casing at a suitable height from the bottom of the cellar pit. The height is calculated as under: Deduct the total height of all the well head components except the tubing spool from the depth of the cellar pit. The height obtained is the height at which the surface casing should be cut from the cellar pit bottom. Care should also be exercised so that welding of the surface casing to the casing head housing can be done easily. 1. The marks are put all around the surface of the casing at a number of points and then a circular marking is done. 2. Cut casing and chamfer properly on the inside. 3. The weld –on housing of the casing head is slipped on the cut casing and is kept perfectly horizontal and welded from both inside and outside using the proper type of welding electrodes. 4. The welded casing head housing is allowed to air cool. 10.1 TYPES OF CASING HEAD HOUSING Casing head housing are available in two different types: 1. Threaded Bottom. 2. Welded Bottom 1. THREADED BOTTOM The threaded bottom housing is furnished with API casing threads so that they may be screwed on to the casing pipe. Both the female as well as male threaded housing are available. a) Female Threaded Bottom This housing is screwed directly on casing and is considered standard since one housing can be used for all weights and grades of a particular size casing. b) Male Threaded Bottom In order to screw the casing head housing directly on to the coupling of the casing, housing with male threaded bottom are used. The use of such housing is discouraged due to the following reasons: 1. In terms of strength the API casing head material is equivalent to J-55 casing. This means that in the event that a male threaded housing is screwed on N-80 or P-110 grade casing, the male thread on the casing head would be the weakest connection because it would be equivalent to J-55. 2. The bore through such type of casing housing must match the casing ID which will vary not only for different casing sizes but also for the different pipe weights within a given range. 85


2. SLIP ON WELD TYPE HOUSING This type of housing is equipped with a socket weld preparation which slips over the casing and has provision for welding top of the casing to the ID of the housing and also for welding the bottom of the housing to the OD of the casing. One housing can be used over all the weights and grades of a particular size casing. Test port is provided to test the quality of welding. Housing/Bowl flange should be aligned with respect to the cellar pit. Outlets on the casing head housing Outlets are provided on the casing head housings for access to the annulus. Threaded outlets, flanged outlets or a combination thereof are available. Either one or two outlets can be provided. 10.2 INSTALLATION OF WELLHEAD SEALS A. Installation of Primary Seals (National Well Head ) 1. Remove burrs from the cut end of the casing, drop the lower packing support with the lip face up over the casing and into the body counter bore. 2. Thoroughly clean and lubricate with oil the casing as well as inner and outer surfaces of seals and put one side of the seal lip over the casing. Tap progressively all around the rubber packing with a hammer until the casing has completely entered the inner lips. Care must be taken to avoid damage to the lips of the rubber packing. 3. After the outer lips have fully entered the bevel in Bowl, drive the packing down until it is flush with the body flange. 4. Place the upper packing support with the lip receiving face down over the casing and drop it into place. B. Installation of Secondary Seals 1. Drop the lower secondary seal packing support with its lip face up over the casing. 2. Install the rubber packing as per procedure explained for installation of primary lip seal packing. 3. Install the upper secondary packing support. 4. Thus secondary packing is installed. Installation of Next Casing or Tubing Spool 1. Place the ring gasket in its groove. 2. Install the next casing spool or tubing spool on to the well head assembly keeping the flanges matching the flange on the casing head on the bottom and bolt up properly. 10.3 TESTING OF CASING HEAD CONNECTIONS 1. After installing the different parts of a well head, testing is carried out to determine the effectiveness of the field installed seals and connections. 2. The pressure should not exceed the lowest pressure determined from the following: • Working pressure of connection. • Load restriction on primary seal. • Collapse pressure of the pipe after taking into consideration safety factor. 86

Well Head Fitting

• • • •

Load restriction on secondary seal. Working pressure of end or outlet connection. Working pressure rating of the spool. Internal yield pressure of pipe after taking into consideration safety factor.

A

D

B

E

C

F

G

Installation of Primary and Secondary Seals (National) 87


10.4 RUNNING PROCEDURE FOR 3 CASING POLICY WELLHEAD (BHEL) SYSTEM DESCRIPTION The Typical production system consists of the following casing sizes: Typical Flange Sizes & Ratings for 3CP WELLHEAD: (1)

3000 psi Wellhead: 13-5/8" - 3000 x 11" - 3000 x 7-1/16” - 3000 psi

(2)

5000 psi Wellhead :13-5/8" - 3000 x 11" -5000 x 7-1/16" - 5000 psi

(3)

10000 psi Wellhead:13-5/8" - 5000 x 11" -10000 x 7-1/16" -10000 psi

ASSEMBLY / CONTRACT DRAWINGS

10.4.1 Installation Procedures 10.4.1.1 13-3/8" Casing and Wellhead Equipment a. Installation of 13-5/8"nominal casing head threaded bottom connection 1. Pick up the 13-3/8" Male threaded Casing of the required length. 2. Pick up the casing head and orientate it, taking into consideration wing valve directions and make up with the Male threaded Casing. 3. Nipple up BOP and riser with the flange connections. b. Slip on welded bottom connection 1. Cut the casing at the desired height above the cellar pit level. Smooth and level the casing. 2. Pick up the casing head and orientate it, taking into consideration wing valve directions and slip it over the casing. 3. Ensure that the casing has entered the socket weld preparation and the Casing Head is seated correctly.

88

Well Head Fitting

4. Remove the ½” LP plug from the Casing Head. Weld the Casing to the Casing Head taking into consideration the material of the Casing Head (Low Alloy Steel) and Casing material combination and stress relieve. 5. After the welds have cooled, seal test the welds via test port to a maximum Working Pressure, but do not exceed 80% of the casing collapse pressure. After successful test, place ½” LP Plug. 6. Nipple up BOP and riser with the flange connections. 10.4.1.2 Running The 13-5/8" Test Plug 1. Make up the 13-5/8" Nom.Test plug assembly to the drill string. 2. Run the 13-5/8" Nom. Test Plug assembly on the drill string and land it in the casing head bowl. 3. Test the BOP and connections above the 13-5/8" Nom. Test Plug Assembly by pressurizing through the drill string and bypass in the 13-5/8" Test Plug assembly. 4. Remove the test Plug after testing. 5. Drill hole for 9-5/8" casing to prescribed depth. Note: It is recommended to use BHEL 13-5/8" Nom. bore protector while drilling to protect the casing head inner surface from damage. 10.4.2 9-5/8" Casing and Wellhead Equipment 10.4.2.1 Installation Of 13-5/8 "Nomx 9-5/8" Casing Hanger Installation of Casing Hanger (BCMBNS / BCMBFNS) is as follows: BHEL Make BCMBNS and BCMBFNS slips incorporate a new controlled make up principle that permits casing string loads equivalent to the pipe body strength to be handled with a controlled pipe Inner Diameter. The design is such that when light to medium casing loads are supported, there are radial gaps between the segments. Increasing the load of the suspended casing completely closes the gaps. The fully loaded slip assembly resembles and reacts as a continuous, solid ring with a fixed Inner Diameter. The dimensions selected for these slips compensate for the tubular mill tolerances, so that maximum casing loads can be supported without reducing the casing Inner Diameter below the API drift diameter. The 45° shoulder on the casing head / spool body furnishes a solid supporting surface for the fully loaded slip unit. A) Type Bcmbns Casing Slips Type BCMBNS casing slips are three piece hinged assemblies with a simple latch permitting them to be closed around the casing and lowered through BOP. B) Type Bcmbfns Casing Slip & Seal Hangers The BCMBFNS hanger is an automatic suspend-and-seal unit. It utilizes a metal hinge and a simple integral latch pin. It can be wrapped around the casing and lowered through preventers. Upon reaching the bowl in the casing body, it grips and suspends the casing string. The annulus is automatically and effectively sealed upon slack off. No manual adjustments are necessary before installation or after slack off. Excessive packing pressure is relieved, avoiding any possibility of deformed casing when maximum string lengths are suspended. Type BB primary packing should be used with this hanger. 89


Item No.

Part Name

No.Off

Material

1

Slip Segment

3

Steel Carburized

2

Drive Pin

5

Hardened Steel

3

Hinge Plate

3

Steel

4

Hinge Pin

1

Steel

5

Eye Bolt

2

Steel

Guidelines for Installing Casing Hangers (Slip Assembly): Fig.1

5 2 1 4

3

Fig:1 : Type Bcmbns Slip Type Casing Hangers 1. Casing shall be spaced so that there shall be no collar located between the points of assembly above the BOP stack and the casing head / spool which would prevent the hangers from sliding down the BOP into position. 2. Hold the casing to desired tension. Do not slack off. 3. Position two boards across the top of the BOP stack / casing head. 4. Remove the hinged pin (Item No.4) to open out the slip assembly 5. Wrap the slip assembly around the casing, place it on the boards and reinstall the hinge pin. 6. Remove the support boards. Lower the slip assembly through the BOP stack / casing head / spool and land it in the casing head / spool. 7. Slack off the casing tension slowly to actuate the slips. No movement of the casing assures that the slips have gripped. 8. Part the BOP stack. 9. Mark and cut off casing approximately 4" (102 mm) above the upper surface of Casing Head Flange. 90

Well Head Fitting

Item No.

Part Name

No.Off

Material

1

Spider

2

60K Steel

2

Slip

4

Steel Carburised

3

Hinge Pin-Fixed

1

Steel

4

Hinge Latch Pin

1

Steel

5

Seal

1

Buna-N

6

Shouldered Screw

4

Steel

7

Pin-Slip (Not shown)

4

Steel

8

Eye Bolt

2

Steel

Guidelines For Installing Bcmbfns Casing Hangers (Slip Seal Assembly) : Fig.2

2

3 8

4 1 6 5

Fig. 2: Type Bcmbfns Slip & Seal Casing Hangers 1. Casing shall be spaced so that there shall be no collar located between the points of assembly above the BOP stack and the casing head / spool which would prevent the hangers from sliding down the BOP into position. 2. Hold the casing to desired tension. Do not slack off. 3. Position two boards across the top of the BOP stack / casing head. 4. Remove the hinge latch pin (Item No.4) to open out the slip assembly. 5. Wrap the slip assembly around the casing, place it on the boards and re-install the hinge latch pin.(Ensure that Item 6 (Shouldered Screws) is free to move and not binding on the body) 6. Remove the support boards. Lower the slip seal assembly through the BOP stack / casing head / spool and land it in the casing head / spool. 7. Slack off the casing tension slowly to actuate the slips. No movement of the casing assures that the slips have gripped. Note : If the slip assembly has not gripped, slip teeth are to be checked for sharpness. 91


8. Part the BOP stack. 9. Mark and cut off casing approximately 4" (102 mm) above the upper surface of Casing Head Flange. 10.4.2.2 Installation Of Primary Packing 13-5/8" Nom X 9-5/8" 1. Pick and drop 13-5/8"Nom x 9-5/8" Primary packing lower support with the lip receiving face up over the casing and seat it into the Casing Head body counter bore. 2. Clean and grease the casing as well as the inner and outer surfaces of the Primary packing and slide one side of the packing lip over the casing. Tap progressively around the packing with a hammer until the casing has completely entered the inner lips. Caution : Do not cut or gouge the lips of the Packing during installation. 3

After the outer lips have fully entered the bevel in the bowl, drive the Packing down until it is flush with the body flange.

Note: If the wing valve outlet is open, entrapped air will not hinder seating of packing. 4. Place the upper packing support, with the lip receiving face down over the casing, drop and drive it until it is flush with the Body Flange. 10.4.2.3 Installation of Secondary Packing 13-5/8"Nom X 9-5/8" Install the Secondary Packing group by dropping the lower support with its lip receiving face up and then install the packing and upper support as described in Step 10.4.2.2. 10.4.2.4 Installation Of Casing Spool 1. Place Ring Gasket in place on the Casing Head flange. 2. Lower the casing spool over the Casing Head flange and carefully orientate it, taking into consideration wing valve directions. 3. Make up the bottom flanged connection with stud bolts and nuts. 4. Hook up test pump to test port on lower flange of Casing spool. Test to maximum Working Pressure or 80% of collapse pressure of casing whichever is minimum. Note : 5. 6. 7.

Remove Check Valve from test port before testing. Bleed off test pressure, remove test pump and install check valve. Reinstall Seal plug. Nipple up BOP and riser.

10.4.2.5 Running The 11"Nom. TEST PLUG BUSHING 1. Make up 11" Test plug assembly to the drill string. 2. Run the 11" Test Plug assembly on the drill string and land it in the casing spool bowl. 3. Test the BOP and connections above the 11"Nom.Test Plug Assembly by pressurising through the drill string and bypass in the 11" Nominal Test Plug assembly. Remove the test Plug after testing. 4. Drill hole for 7"/ 5½” casing to prescribed depth. Note : It is recommended to use BHEL 11" Bore Protector while drilling to protect the Casing Spool inner surface from damage. 92

Well Head Fitting

10.4.3 7" / 5½” CASING AND WELLHEAD EQUIPMENT 10.4.3.1 Installation of 11 "Nom x 7" / 5½” Casing Hanger See Sl. No. 2.2.1 for construction and installation of the Casing Hanger (BCMBNS/ BCMBFNS) . 1. Run the 7"/ 5½” casing. Space out the casing so that there is no collar located between the point of assembly above the BOP stack and the Casing Head/spool which would prevent the hanger from sliding down the BOP into position. 2. Center and Hold the 7" / 5½” casing to desired tension. Do not slack Off. 3. Position two boards across the top of the BOP Stack. 4. Open the hanger assembly by removing the latch pin wraps it around the 7" / 5½” Casing, place it on the Board and make up the latch pin. Note : Type BCMBFNS - Casing Hangers is an automatic suspend and seal unit. It utilizes a metal hinge pin and a simple integral latch pin. It can be wrapped around the casing and lowered through BOP. Upon reaching the bowl in the casing spool body, it grips and suspends the casing string. The annulus is automatically and effectively sealed off upon slack off. No manual adjustments are necessary. 5. Remove Support boards. Lower the hanger through BOP Stack and make sure that the Hanger has seated in the Casing Spool. 6. Slack off the tension slowly to actuate the slips. Ensure that the slips have gripped the.casing securely. 7. Part the BOP stack. 8. Mark and cut off casing approximately 4" (102 mm) above the upper surface of Casing Spool Flange. 9. Remove burrs from the cut edges of the casing and ensure that the edge is smooth and level. 10.4.3.2 Installation of Primary Packing 11"Nom x 7" / 5½” 1. Pick and drop 11"Nom x 7"/ 5½” Primary packing lower support with the lip receiving face up over the casing and seat it into the Casing Spool body counter bore. 2. Clean and grease the casing as well as the inner and outer surfaces of the Primary packing and slide one side of the packing lip over the casing. Tap progressively around the packing with a hammer until the casing has completely entered the inner lips. Caution: Do not cut or gouge the lips of the Packing during installation. 3. After the outer lips have fully entered the bevel in the bowl, drive the Packing down until it is flush with the Body Flange. Note: If entrapped air hinders seating of packing, relieve the entrapped air through the inner / outer side of the primary packing using a screw driver. 4. Place the upper packing support, with the lip receiving face down over the casing, drop and drive it until it is flush with the Body Flange. 10.4.3.3 Installation of Secondary Packing 11"Nom. - 7" / 5½” Install the Secondary Packing group by dropping the lower support with its lip receiving face up and then install the packing and upper support as described in Step 10.4.2.3. 93


10.4.3.4 Installation of tubing spool 1. Place Ring Gasket in place on the Casing Spool flange. 2. Pick up TUBING SPOOL and orientate it, taking into consideration wing valve directions and lower it over 7"/ 5½” Csg. carefully. 3. Make up the bottom flanged connection with stud bolts and nuts. 4. Hook up test pump to test port on lower flange of tubing spool. Test to maximum Working Pressure or 80% of collapse pressure of casing whichever is minimum. Note : Remove Check Valve from test port before testing. 5. Bleed off test pressure, remove test pump and install check valve. 6. Reinstall Seal plug. 7. Nipple up BOP and riser. 10.4.3.5 Running the 7-1/16 "Nom. Test Plug Bushing 1. Make up 7-1/16" Test plug assembly to the drill string. 2. Run the Test Plug assembly on the drill string and land it in the Tubing spool bowl. Note: Anchor screws on the Tubing head are to be backed out before lowering the 7-1/16" Nom. Test plug assembly. 3. Test the BOP and connections above the 7-1/16" Test Plug Assembly by pressurising through the drill string and bypass in the 7-1/16" Test Plug assembly. 4. Remove the test Plug after testing. 5. Drill hole to suit the 3½” / 2-7/8" Tubing. Note : It is recommended to use BHEL 7-1/16"Bore Protector while drilling to protect the Tubing Spool inner surface from damage. 10.5 3½” / 2-7/8" TUBING AND WELLHEAD EQUIPMENT 10.5.1 Installation of 7-1/16" Nominal Tubing Hanger 1. Run the Tubing (along with Control line simultaneously, in case Control line provision is required) with the last joint suspended in the rotary slips. 2. Make up the Tubing Hanger bottom connection to the last joint of tubing to be run. Ensure that the Neck Seals are fitted in their respective grooves. In case of Control line provision, install the control line assay in the following manner: a) Install swage lock fitting in the bottom of Hanger body. Tighten the fitting. b) Connect the control line to the Tubing Hanger inlet. Strap the control line with the Tubing. 3. Connect the Back pressure valve Plug in the Back pressure valve and install the Assembly in the Hanger. 4. Ensure that the Anchor Screws around the Tubing Spool are backed out. 5. Lower the Tubing Hanger through the BOP stack into the Tubing spool bowl. 6. Run in the Anchor Screws around the Tubing Spool to hold the Tubing Hanger in place. 7. Back out and retrieve the landing joint. 8. Nipple down the BOP stack and riser, being careful not to damage the sealing surfaces on the Tubing Hanger. 94

Well Head Fitting

10.5.2 INSTALLATION OF X-MAS TREE The complete X-mass tree has been assembled and tested in the plant prior to delivery to the well site. 1. Inspect Ring grooves at the bottom of X-Mass tree and top of Tubing Spool. 2. Install Ring Joint Gaskets in the Tubing Spool. 3. Lower the X-MAS TREE on to the Tubing Spool and make up the Flanged connection using the Stud bolts and nuts. 4. Test the connection through the test port on the bottom flange of X-mass Tree Bonnet. 5. In case of provision for Control line exit through Bonnet, connect the control line in the following manner: 6. Install swage lock fitting at the Bonnet exit location. Tighten the fitting. 7. Connect the control line to Bonnet Exit. 8. Open all Valves. 9. In the case of Actuator operated valves, remove the 1/2" NPT Seal Plug and apply the Rated Control line pressure through the 1/2" NPT Inlet Port. Then remove the Thread Protector and Shipping Washer. Reinstall the Thread protector. 10. Test Tree to the Rated Working pressure.

95


CHAPTER - 11

BOP STACK 11.1 BLOWOUT PREVENTER SIZING The required BOP equipment must be selected in such a manner that vertical bore is sufficient enough to pass the casing, casing hanger, casing slip and seal assembly, bit and other drilling tools likely to be used and the following points must be kept in mind while selecting the BOP stack. A. Space between top of cellar pit and bottom of rotary table Blowout preventer stack configuration is to be selected on the basis of available space and for different types of rigs owned by ONGC. B. Matching connection to the size & press rating of w/head flanges At different stages of drilling, the BOP stack is installed on various section of wellhead. If the rated working pressure and size of wellhead flange does not match with the BOP stack, it leads to the use of adopter flanges. While designing BOP stack efforts should be made to use minimum number of flange connections on the stack. Working pressure rating of wellhead should be equal or more than the maximum expected surface pressure as estimated for selection of blowout preventer. C. Service conditions Service conditions refer to the following aspects: 1. Environment operations i.e. urban, rural or isolated place to ensure required degree of protection for men, equipment and ecological environment. 2. Corrosiveness of drilling fluids and formation fluids: e.g. H2S environment requires H2S trim blowout prevention equipment to resist Sulphide stress cracking. Some blends of drilling and completion fluids can have detrimental effects on elastomer compounds. The original equipment manufacturer should be consulted regarding compatibility with drilling and completion fluids. 3. Availability of BOP spare parts at drill site, storage facilities (specially for rubberized parts), inventory management, etc. Nitrile elastomeric components may be suitable for H2S service provided drilling fluids are properly treated. 4. Infrastructure facilities to repair test and replace BOP and its sub assemblies. D. Minimum requirement criteria a) BOP stack must withstand the maximum well head pressure estimated as per calculations. b) The internal bore should be large enough to pass the drilling tools and tubulars required for the subsequent operations. c) The stack must have provision for inlet and outlet of fluid under controlled pressure. d) Annular BOPs may have a one step lower rated working pressure than the ram BOPs.

96

BOP Stack

Table Rated working pressure, psi

Min. vertical bore, in

Ring joint gasket R / RX

2M 3M

5M

10 M

15 M / 20 M

16 ¾ 21 ¼ 7 1/16 9 11 13 5/8 20 ¾ 7 1/16 11 13 5/8 16 ¾ 18 ¾ 21 ¼ 7 1/16 9 11 13 5/8 16 ¾ 18 ¾ 21 ¼ 7 1/16 9 11 13 5/8

65 73 45 49 53 57 74 46 54 -

BX 160 162 163 165 156 157 158 159 162 164 166 156 157 158 159

M = 1000 psi 11.2 NOMENCLATURE Blowout prevention system consists of blowout preventer stack, kill line, choke line, choke and kill manifold, closing unit, diverter and auxiliary equipment. Component code adopted for designation of BOP stack configuration as per API RP-53 is given below: G - Rotating head A - Annular type blowout preventer R - Single ram type preventer Rd - Double ram type preventer with two sets of rams. Rt - Triple ram type preventer with three sets of rams. S - Drilling spool with side outlets for connecting choke and kill lines. M - 1000 psi rated working pressure.

97


Components are listed reading upwards from the uppermost piece of permanent well head equipment or from bottom of the preventer stack. A blowout preventer stack may be fully identified by a very simple designation such as : 5M, 13 5/8”, RSRdA. This preventer stack would be rated 5000 psi working pressure and would have through bore of 13 5/8”. Ram type preventers should be equipped with extension hand wheels for manual locking or hydraulically operated locks. 11.3 BASIC COMPONENTS OF BOP STACK a) Annular Preventer The Annular Preventer is designed to close and seal over the open hole or around different shapes such as square and hexagonal kelly, tool joint etc including wire line except stabiliser and bit. b) Ram Type Preventer Pipe ram is designed to close and seal around a pre designated size of pipe, whereas, presently available variable rams can seal around a pre designated range of pipe size. Blind ram is used to close and seal an open hole. However, these days blind cum shear rams are in use, which can shear the pipe and seal the open hole as well. Note : Pipe rams are not designed to close and seal around tool joint and coupling. c) Drilling Spools Choke and kill lines may be connected either to side outlets of the BOPs or to a Drilling spool installed below at least one Ram BOP. Utilization of the BOP side outlets reduces the number of stack connections and over all BOP stack height. However, a drilling spool is used to provide stack outlets (to localise possible erosion in the less expensive spool) and to allow additional space between preventers to facilitate stripping, hang off, and/or shear operations. Criteria for Drilling Spools a) 3M and 5M arrangements should have two side outlets no smaller than a 2-inch nominal diameter and be flanged, studded, or hubbed. 10M, 15M, and 20M arrangements should have two side outlets of minimum 3-inch nominal diameter and should be flanged, studded or hubbed. b) It shall have a vertical bore diameter equal to that of mating BOPs and at least equal to the maximum bore of the upper most casing/tubing head. c) It shall have a rated working pressure equal to the rated working pressure of the installed ram BOP. For drilling operations, well head outlets should not be employed for choke and kill lines. d) Choke Manifold and Choke Lines The choke manifold consists of high pressure pipe, fittings, flanges, valves and manual and/or hydraulic operated adjustable chokes. This manifold may bleed off well bore pressure at a controlled rate or may stop fluid flow from the well bore completely, as required. Choke Manifold Recommended practices for installation (Surface installation): 98

BOP Stack

a) Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal to or greater than the rated working pressure of the ram BOPs in use. b) The choke manifold should be placed in a readily accessible location, preferably outside the rig structure. c) All choke manifold valves should be full bore. Minimum two valves are recommended in choke line immediately after the BOP stack with rated working pressure equal or greater than the rated working pressure of Ram BOP in use. One of these two valves should be remotely controlled. During operations, all valves should be either fully opened or fully closed. d) A minimum of one remotely operated choke should be installed on 10000 psi and above rated working pressure manifolds. Generally, remote operated choke is not installed in 5000 psi working pressure manifold. If conditions dictate like for example the frequency of use of chokes is high, it will be prudent to use a remote choke (in addition to adjustable choke) in 5000 psi working pressure choke manifold. Choke manifold configurations should allow for re-routing of flow without interrupting flow control. e) Pressure gauges suitable for operating pressure and drilling fluid service should be installed so that drill pipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted. f) Rig air systems should be checked to ensure their adequacy to provide the necessary pressure and volume required different controls. The remotely operated choke should be equipped with an emergency back up system such as a manual pump for use in the event air becomes unavailable. Installation guidelines – choke lines The choke line and manifold provides a means of applying back pressure on the formation while circulating out influx from the well bore. The choke line and lines downstream of the choke should: a) 1. Be as straight as possible. Wherever the bends, blocks and tees are provided, they should be targeted to minimize erosion. 2. For flexible lines, manufacturer’s guidelines should be consulted on working minimum bend radius to ensure proper length determination and safe working configuration. b) Be firmly anchored to prevent excessive whip or vibration. c) 1. Have a bore of sufficient size to prevent excessive erosion or fluid friction. Minimum recommended size for choke lines as per API is 2” nominal diameter or 3M and 5M arrangements and 3” nominal diameter for 10M and above rated arrangements. 2. Minimum recommended nominal inside diameter for lines downstream of the chokes should be equal to or greater than the nominal connection size of the chokes. 3. For air or gas drilling operations, minimum 4” nominal diameter lines are recommended. 4. The bleed line that bypasses the chokes should be at least equal in diameter to the choke line. Kill lines and kill manifold Kill lines are an integral part of the surface equipment required for well control during drilling. The kill line system provides a means of pumping into the well bore when the normal method of circulating down through the kelly or drill pipe can not be employed. The kill line connects the drilling fluid pumps 99


to a side outlet on the BOP stack. The location of the kill line connection to the stack depends on the particular configuration of BOPs and spools employed; the connection should be below the ram type BOP most likely to be operated. Installation guidelines - kill lines a) All lines, valves, check valves and flow fittings should have a working pressure at least equal to the rated working pressure of the ram BOPs in use. b) For working pressures of 3000 psi and above, flanged, welded, hubbed or other end connections that are in accordance with API Specification 6A, should be employed. c) Components should be of sufficient diameter to permit reasonable pumping rates without excessive friction. The minimum recommended size is 2-inch nominal diameter. d) As per API, two full bore manual valves plus a check valve or two full bore valves (one of which is remotely operated) between the stack outlet and kill line are recommended for installations with rated working pressure of 5000 psi or greater. e) Lines should be as straight as possible. When bends are required to accommodate either dimensional variations on sequential rig ups or to facilitate hook up to the BOP, the largest bend radius allowable under the hook up restraints should be provided. For flexible lines, manufacturer’s guidelines should be followed to ensure safe working configuration. f) All lines should be firmly anchored to prevent excessive whip or vibration. g) The kill line should not be used as fill-up line during normal drilling operations. Standard choke and kill manifold The standard choke and kill manifolds in use/ available in ONGC are: i) 4 1/16” –5000 psi working pressure. ii) 4 1/16” –10000 psi working pressure. iii) 3 1/16” –15000 psi working pressure. 11.4 INSTALLATION OF BOP The first step in fitting BOP is the installation of a drilling spool over well head. 1. Clean the casing head flange and put steel ring gasket of correct type and rating. 2. Clean both the flanges of the spacer spool, if required to use. 3. Fit a spacer spool above the casing head. The length of the spacer spool should be so adjusted that the upper face of the spacer spool comes in line with the ground level. Both the flanges of the spacer spool should be of the same rating and size as the casing head flange. 4. Install Ram type preventor equipped with pipe rams matching with drill pipe sizes to be used (incase of 10,000/15,000 psi BOP stack). 5. Install drilling spool on the spacer spool or pipe ram BOP, if needed. 6. Care should be taken to select the drilling spool having flanges of same pressure rating as that of the BOP. 7. The two diametrically opposite side outlets should have the same pressure rating as choke and kill lines respectively. 8. The vertical bore should be at least equal to the maximum inner diameter of the inner most casing. 9. While installing drilling spool, the two side outlets of the spool should point in the direction in which choke and kill lines are to be fitted. 100

BOP Stack

10. Lift double ram BOP so that the BOP’s upper position in on the top side. Top rubber seal of the rams should be on the upper side. The arrow marking on BOP also indicates top position. 11. Place the correct ring gasket in the groove on the drilling spool. 12. Slowly tower BOP (the direction of the BOP handles should be so kept that BOP rams can be easily operated) and rest BOP on the drilling spool. 13. Tighten the double ram BOP on the drilling spool (in case the studs can not be put from below the drilling spool or from above the BOP then the same are to be positioned in the drilling spool before lowering BOP). 14. Clean the top ring groove of the ram type BOP, put the ring gasket of correct size and rating. 15. Lift annular BOP and slowly install it above double ram BOP taking proper care to keep the fluid outlet valves on the sides so that the fluid lines can be easily fitted. 16. Clean the ring groove above the annular BOP and install the ring and the flow nipple to facilitate the flow of mud from the well bore to the shale shaker. 17. Connect BOP handles on the double ram BOPs ensuring that manually operated shafts and wheels must extend beyond the substructure boundary and be easily accessible. 18. Erect a shield of wooden planks over control wheels of preventers and on the wall in front of the hand wheel, the direction and number of turns which are required for preventer closure should be displayed by an arrow in red paint. Installation of Choke and Kill Line Kill Line 1. Fit the adapter spool with the drilling spool. 2. Using proper ring gasket and studs and nuts tighten two valves of proper rating with the adapter spool. 3. Install one tee after the valves and fit a pressure gauge in the blind flange having threaded opening for fitting the pressure gauge. 4. Install one non – return valve. 5. Install one tee of proper rating. 6. Install the line from mud pump on one side and a line from the cementing unit from the other side of the tee. Install valve on this line. Choke Line 1. Install the adapter spool (if required). 2. Connect one valve (stand by valve). 3. Install the remote control hydraulic valve. 4. Connect choke flow line having flanges of required rating at both the ends between the hydraulically operated valve and the choke manifold. Choke Manifold 1. As chokes get worn out due to erosion or plugging with large formation particles it is essential to provide chokes in parallel to the flow line, thereby necessitating the installation of a manifold called the choke manifold. 2. Hydraulically operated or manually operated chokes are installed in the choke manifold. 3. Strategically placed gate valves will permit the use of one choke while the others are disconnected. 4. Two valves should be installed ahead of each choke to be used for regulating the flow. 101


5. The choke manifold should have one connection from the manifold after the choke to the mud tank and one connecton to the flare line. 6. The pressure rating of various valves in the choke line prior to choke and in the full bore line should be equal to or more than the pressure rating of the BOP. 11.5 RECOMMENDED PROCEDURE FOR TESTING BOP STACK AND ALLIED EQUIPMENT Since all the equipments used in well control are essential to the safety of the well, the crew members, the rig and the surrounding environment; testing procedures of these vital surface BOP equipment becomes an important integral part of the drilling programme. For optimum control of any well kick situations successful functioning of the blowout preventer stack, choke and kill lines and other related equipment at their rated capabilities becomes pertinent. The only way to make certain and ensure that the equipment will perform at its rated capacity when needed is by adhering to regular test procedures. The situation requires both rigorous test procedures that evaluate pressure integrity of all parts in the system and at the same time exposing the equipment to periodical function tests will keep the equipment in readiness for operations in addition to suggesting if any maintenance work is required to be carried out in advance. All the important considerations for BOP stack testing and the test procedures are discussed. 11.5.1 Need of Periodic Testing Considering many likely causes of failure of blowout preventer equipment, the need for periodic testing of BOP’s assumes a great importance and is a must. The purpose of various field tests of BOPs (well control equipment) is to verify: a) Those specific functions are operationally ready. b) The pressure integrity of the installed equipment. c) The control system and BOP compatibility. It becomes pertinent to identify the causes and take remedial measures in order to rectify the same. 11.6 REASONS OF FAILURE OF BOP STACK AND CHOKE AND KILL MANIFOLD • Equipment may not have been installed properly. • Vibrations and extra loading during drilling operation may cause leak. • Lines and fittings may be abraded by mud flow. • Cement, baryte and sand may sometimes accumulate or settle out and plug. • Corrosion may cause damage to choke lines & equipment. • Partially closed valve may get eroded. • With passage of time, rubber sealing elements may get deteriorated and fail when subjected to test conditions. • Badly stored items, when used may not perform at rated capacity. • Normal wear and tear also results in malfunction of the equipment. • Rubber sealing elements and packers may not be compatible with the mud system or subsurface environment such as temperature. 11.6.1 Important Considerations Important considerations in blowout preventer testing are :

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BOP Stack

• • • • •

Test fluids Test pressures Testing equipments Test procedures and their frequency Test duration

A. Test Fluids In normal application, clear water is considered as the best test fluid, as drilling fluid may plug small leaks. It should be ensured that air is removed from the system before test pressure is applied. B. Test Pressures All BOP components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi and then to a high pressure. i.

Low pressure test: The stack is generally washed and cleaned with water before testing. However, it is possible that existence of dry mud particles may be covering a potential leak spot. In such cases high pressure test may pack the mud particle in the leak spot and affect a temporary seal. Hence low pressure test of 200 to 300 psi is recommended for rams , annular preventers, manifolds, lower kelly cock, etc. Also in performing a low pressure test, do not apply a high pressure and bleed down to low pressure. Should a leak occur at low pressure, corrective remedial measure may be taken accordingly at this stage.

ii. High pressure test: After initial installation of BOP on well head, i. Rams, choke manifold and choke/ kill lines should be tested to the rated working pressure of the ram BOPs or to the rated working pressure of the well head on which the stack is installed, which ever is lower. ii. Annular BOPs may be tested to 70% of the rated working pressure or to the test pressure applied to the ram BOPs, which ever is lower. iii. Lower kelly cock, kelly, upper kelly cock and drill pipe safety valve should be tested to the rated working pressure. iv. In case of instances where available BOP stack and / or the well head has higher working pressure than are required for the specific well bore conditions due to equipment availability, a site specific well control test programme can be followed. Subsequent high pressure test of ram BOPs and choke manifold should be limited to a pressure greater than the maximum anticipated surface pressure but not to exceed the working presure of the ram BOPs. The maximum anticipated surface pressure should be determined by the operator based on specific well conditions. Annular BOPs should be tested to a minimum of 70% of their working pressure or to the test pressure of ram BOPs, which ever is lesser. In case of downstream valves of choke and kill lines, test pressure on initial as well as subsequent tests should be limited to 50% of its rated working pressure. C. Test Duration A stable low test pressure as well as stable high test pressure should be maintained for at least 5 minutes. 103


D. Test Frequency Function test: All operational components of the BOP equipment systems should be function tested at least once a week. Pressure test: Pressure test on the well control equipment should be conducted at least a) Prior to spud or upon installation b) After the repair/ disconnection of any pressure containment seal in the BOP stack, choke line or choke manifold, but limited to the affected component. c) Not to exceed 21 days. E. Testing Equipment Following equipments are usually used while testing BOP equipment : a) Pumps: The pumps used to generate pressures for testing may be any type i.e. capable of attaining the desired pressures. A small high pressure pump is generally used in most of the testing applications. Cementing units with of desired high pressure rating can safely be used if conveniently available. b) Test plugs: While testing BOP stack and other equipment, test plug must be used to isolate the entire casing and open hole from the applied test pressures. These test plugs are set in the bottom of the preventers, there by preventing communication of pressure below the test plug. c) Commonly used test tools are : • cup tester • test plug

Fig. 2. Test Plug

Fig. 1. Cup Tester

Fig. 3. Testing BOP with Cup Tester / Test Plug

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BOP Stack

Cup Tester It has a mandrel with box connection on top, a cup and a sub with pin connector on bottom. The cup of the tester gives effective sealing in the casing. At the time of pressure testing, the cup tester is made up on drill pipe and should be lowered to be placed in the casing opposite to the slips in the casing spool or casing head. After filling the stack with water, the pipe rams or the annular is closed. Pressure is built up by pumping down the kill lines to provide desired pressure. The limitations of the cup tester: 1. Since cup tester is freely hanging in the casing, tension load on pipe will increase with increase in test pressure. Higher grade of drill pipe to be used as test pipe other wise yield strength of drill pipe may limit the test pressures. 2. BOP pressure test will be limited to 70-80% of the burst rating of upper part of casing. 3. This can not be used to test blind/ shear blind rams. Test Plug Test plugs have mainly a box on top to connect test pipe and pin on bottom to add some weight on it. These test plugs are designed to seat in well head. With seal on the body it isolates the upper part of the well head and the well bore. This plug is to be lowered and landed into the well head with a test drill pipe joint after adding few stands of HWDP or equivalent weight to the bottom. This added weight of drill collars will help in seating properly in the well head and give proper sealing. To test the blind or shear blind ram, test pipe should be removed, leaving the test plug resting on the well head. Care must be taken while using test plug for its designed compatibility with the existing well head used. Different makes of well head have different types of test plugs. So, while lowering test plug it should be confirmed this plug is compatible with the well head used other wise it may get stuck and can lead to another problem which will result in loss of valuable rig time. d) Casing ram test sub: To facilitate testing of casing ram it is essential to have the casing ram test sub. It can be connected between the test plug and test joint after making suitable end connections so that the sub is positioned against the casing ram to be tested. F. Testing Procedure Testing procedures are integral part of the drilling program and as such a specific programme of equipment testing is mandatory. Testing procedures are discussed under heads: • function (actuation) testing • pressure (hydraulic) testing FUNCTION TEST Function test is performed to verify the component’s intended operations. i. The test (ram BOP and annular BOP) should be conducted when the drill string is inside casing. ii. Test should be conducted after installing FOSV/ inside BOP on drill string. iii. Both pneumatic and electric pump of accumulator unit should be turned off after recordinginitial accumulatorpressure. 105


iv. All the ram preventers ( except blind/shear) and HCR’s in choke/kill line should be functiontested and closing time should be recorded. v. Blind ram should be operated for function test when drill string is out of hole. vi. Pipe ram should be closed against correct size pipe in the hole. vii. Operation of shear ram should be kept to bare minimum. viii. Closing time should not exceed 30 seconds for all ram preventers and annular preventers smaller than 18 3/4” closing time should not exceed 45 sec for annular preventer of 18 3/4” and larger size. ix. Function test should be carried out alternatively from main control unit/derrick floor panel/ auxiliary panel. x. Record final accumulator pressure after all the functions should not be less than 1200 psi or 200 psi above the pre charged pressure of accumulator which ever is maximum. xi. All the gate valves and blow out preventers should be returned to their original position and continue normal operations. xii. All the results should be recorded in the prescribed formats. PRESSURE TESTING Testing of Blind Ram (Ref fig. 4) i. Make up appropriate casing head test plug on a stand of drill collar and run in the same on a joint of drill pipe. Set the plug in casing head seat. Back off and remove drill pipe joint. Ensure that test plug size, shape and contour matches with that of casing head where it will seat. ii. Fill preventers with water. Open all the valves and chokes in choke line and choke manifold and allow water to flow through each out let. Flush all the lines and BOP with water. iii. Open both the valves on casing head below test plug seals to recognize leaking seals as well as well activity and prevent formation or casing damage in case of any leakage through test plug. iv. Close valve nos. 7,9 on choke line and valve nos. 2,3 on kill line and close valve no.43. v. Fill and top up BOP with water. vi. Close blind ram with 1500 psi closing pressure. vii. Check closing line and preventer for leaks. viii. Apply pressure by cementing unit or high pressure test unit through main kill line and pressurise upto 200 to 300 psi and hold for 5 minutes. If pressure is holding, test up to final test pressure as decided. Again hold for at least for 5 minutes. ix. If there is a drop in pressure, check all the valves, flanges, and seals that are under pressure. Also check blind ram and test plug for leaks. If leakage is observed corrective action may be taken after releasing pressures and opening blind ram. Retest the blind ram as detailed above. x. Open blind rams with 1500 psi. Check opening lines for leaks. xi. Record test results.

106

BOP Stack

TESTING OF BLIND RAM

40

35 36 34 33

39 38

37

41 42

LEGEND

FLOW DIRECTION VALVE CLOSED VALVE OPEN

FROM MUD PUMPS

ANNULAR 29 CHOKE MANIFOLD PIPE RAM

13

25

14 20

BLIND RAM 43 FROM CEMENTING PUMP

KILL LINE 4

5

15

21

16 17

23

CHOKE LINE

6

9

10

11 12

PIPE RAM 18 1 CASING HEAD

2

3

7

26

30

22

24 27

19

8

28 TESTING PLUG WITH PORTS

31

Fig. 4. Testing of Blind Ram

Testing of Annular BOP and Pipe Rams (Ref fig. 5) i. Flush lines flushed with water. ii. Make up test plug with sufficient weight and rest test plug at well head. iii. Run in appropriate size (smallest size of drill pipe to be used in case of testing of annular BOP) of drill pipe and make up with test plug. iv. Ensure that integral port in the test plug is open. v. Fill up drill pipe with water. Make up FOSV on top of drill pipe. vi. Close valve No 7,9 on choke line and valve no 3,6 on kill line. vii. Close annular preventer with appropriate closing pressure as per manufacture recommendation. viii. Check closing line and annular preventer for leaks.

107


TESTING OF PIPE RAMS AND ANNULAR BOP

35

40 36

34

39 37

33

TEST PRESSURE THROUGH DRILL PIPE

41

38

42

LEGEND

FLOW DIRECTION VALVE CLOSED

FROM MUD PUMPS

VALVE OPEN ANNULAR

29

CHOKE MANIFOLD

PIPE RAM 13

25

14 BLIND RAM

43 FROM CEMENTING PUMP 32

KILL LINE

4

5

20 15

CHOKE LINE

6

9

10

11 12

26

21

16 17

23

18

24

22

30

PIPE RAM

1

2

3

7

19

8

CASING HEAD

27

28 TESTING PLUG WITH PORTS 31

Fig. 5. Testing of Annular BOP and Pipe Rams

ix. Apply test pressure through drill pipe and raise pressure to 200 to 300 psi and hold for 5 minutes. Check for any leakage. If pressure is holding, increase the pressure upto final test pressure and hold for at least 5 minutes. x. Check for leaks and release pressures. xi. Open annular preventer. xii. Now close upper pipe ram with 1500 psi. xiii. Check closing line and preventer for leaks. xiv. Again, apply test pressure through drill pipe and raise pressure upto 200 to 300 psi and hold for five minutes. Check for any leakage. If the pressure is holding, then increase the pressure upto final test pressure and hold for at least 5 minutes. xv. Test pressure should be limited to the pressure rating of the weakest member exposed to the test pressure. xvi. Check for leaks and release pressures. xvii. Open pipe rams with 1500 psi. 108

BOP Stack

xviii.Check opening lines and preventer for leaks. xix. Test all other pipe rams in this manner by repeating step no. ix to xiv. Make sure that the pipe rams size fits the drill pipe size in the well, if not change the drill pipe and then test the rams. Variable bore rams should be initially pressure tested on the largest and smallest OD pipe sizes that may be used during the well operations xx. If there is any leakage, corrective action may be taken after releasing pressure and retested as per procedure detailed above. Testing of Kill Line, Choke Line, Manifold Valves, Flanges and Fittings (Ref fig. 3) From the previous test with the test plug seated in casing head, the procedure mentioned below is followed to conduct the above test: i.

Kill and choke lines and manifold fittings are flushed with water. For this purpose, close upper pipe ram and open all valves and chokes on choke manifold to allow the flow of water through each outlet. ii. Close valves 3,6,7 and9 keeping upper pipe ram closed. iii. Apply test pressure through drill pipe and raise pressure upto 200 to 300 psi and hold for 5 minutes. Check for any leakage. If pressure is holding, then increase the pressure up to the rating of the weakest member exposed to test pressure (same as that of ram BOP) and hold for 5 minutes. iv. Next, open valves 3,6,7 and 9 and close 2,5,8 and 10. Repeat step 3. v. To test check valve 1, open valve 2 and repeat step 3. Next close valves 44,32 and open valve 2. Repeat step 3 to test check valve 4. vi. Close valves 6,45 and open valve 2. Repeat step 3 to test 44 and 45. vii. Open valves 44,45 and close 46. Repeat step 3 to test 46. viii. Remove the spring loaded valve in the check valve no. 4 , so that other valves in the kill line can be tested. ix. Now close valves 43,11,12 and open valves 8,10. Repeat step 3. x. Open valve 43 and close valve 37 and open valve 11 and close valves 15,16 and 17. Repeat step iii. xi. Open valve 37 and close 36,38,39 on kill line side. On choke manifold, open valves 15,16,17 and close valves 14,18 21,22 and 23. Repeat step iii. xii. Next open valves 36,39 and close valves 33,34,35,40,41,42 on kill line side and open valves 14,18,21,23 and close choke 13,19,20,24 on the manifold. Repeat step iii. xiii. Now open chokes 13,19,20,24 and close valves 25,26,27 and 28. xiv. Apply test pressure and raise upto 200 to 300 psi and hold for 5 minutes. Check for any leakage. If pressure is holding, increase the pressure up to 50 % of the rated working pressure of components down stream of chokes. Hold pressure for at least 5 minutes. xv. Finally, open valves 22,25,26,27,28 and close valves 29,30,31. Repeat step xi. xvi. Check all valves, flanges and seals which are subjected to test pressure for leaks. xvii. Release pressure and rectify the leakages if any. Re test the rectified components.

109


TESTING OF CHOKE AND KILL MANIFOLD VALVES

35

40

36

LEGEND

34 33

39 38

37

FLOW DIRECTION

TEST PRESSURE THROUGH DRILL PIPE

41 42

FROM MUD PUMPS

VALVE CLOSED VALVE OPEN

ANNULAR 29 CHOKE MANIFOLD PIPE RAM

13

25

14 BLIND RAM

20

43 FROM CEMENTING PUMP

15

4

5

6

9

10

11 12

16 17

PIPE RAM 18 1 CASING HEAD

2

3

7

26

21

CHOKE LINE

KILL LINE

23 24 19

8

30

22

TESTING PLUG WITH PORTS

27

28 31

Fig. 6. Testing of Kill Line, Choke Line, Manifold Valves, Flanges and Fittings

xviii.Record test pressures. xix. Install check valves on the auxiliary and main kill line respectively. xx. Remove test plug along with drill collar. 11.7 TESTING OF KELLY COCKS AND ROTARY HOSE Pick up kelly, install full open safety valve on bottom of lower kelly cock. Using an adapter, connect to a high pressure test pump or cementing pump. Open appropriate stand pipe valves and kelly valves. Fill system with water and close stand pipe valve. Pressurise to test rotary hose and kelly cocks in sequence. An alternate method for testing kelly cocks and rotary hose will be to apply test pressure through kill lines with test plug seated and pipe ram closed. Here, it is to be ensured that the port provided on the test plug body should be open.

110

BOP Stack

Casing Test 1. After testing of BOPs and choke and kill manifold,, the following sequence of operation are followed to test casing. 2. Run in drill string and bit, up to the top of the cement. 3. Break circulation and test casings to 200 psi greater than the anticipated shoe test pressure. Do not exceed 80% of the burst rating of the casing. Drilling of Cement, Float Collar and Float Shoe 1. Drill cement at 3 – 4 tonnes of weight on the bit and rotary rpm as 50-60 only. 2. Drill float collar and float shoe carefully. 3. Continue drilling till 0.5m below the casing shoe – formation should not be opened. 4. Circulate the cuttings out of the well. Shoe Test This test is done to determine the complete of cement job around the shoe. 1. Pull the drill string in the casing. 2. Close pipe ram BOP and kelly cock. 3. Make cementing unit connection with choke line. 4. Flush the BOP stack, kill and choke lines with water. 5. Close gate valve on kill line. 6. Calculate the shoe test pressure. This is the sum of surface pressure and the hydrostatic pressure of the fluid being used during the test. It is equal to the hydrostatic pressure at the shoe of the heaviest mud that will be used in the well before running the next string of casing volume pumped. (for plotting the graph see leak off test). 7. If the shoe is hermetical, the plot will be linear. 8. Hold the required test pressure for 15 min. The shoe is considered OK if the pressure does not fall more than 10% of the test pressure during this time. 9. Release the pressure through choke line, and measure the volume of fluid recovered and compare this with the volume pumped. Both the volumes should be almost equal. 10. Open Kelly cock. Note: In case the shoe does not hold up to the required pressure, squeeze cement and report all the procedure for testing shoe. 11.8 MUD LINE SUSPENSION SYSTEMS Mud line suspension systems provide temporary abandonment and re-entry capability for exploratory, delineation, template, and other wells drilled from bottom-supported rigs. The various MLS systems available in the market of leading brand Vetco are: 11.8.1 MLH Mudline Suspension System The MLH midline suspension system has short, compact casing hangers with casing threads top and bottom.

111


13-3/8” Mudline Hanger

20” Mudline Hanger 20” Landing Rig 9-5/8” Mudline Hanger

This system is used when a casing load suspension system is required but it is not to be used to run and tieback at the mud line. The MLH system is ideally suited for use on development platforms, and allows a major portion of the casing loads to be suspended at the mud line during drilling and completion of platform wells with traditional surface equipment. It can also be used during jack-up drilling operations. There is standard casing connections on top and bottom of each mud line casing hanger Shoulders support the loads of the concentric casing strings, transferring the loads through the collet to the previously installed hanger.

112

BOP Stack

11.8.2. Mud line MLC-E Suspension System

20” Running Tool 20” Tieback Latch and Lock Tool

13/38” Running Tool

13/38” Tieback Latch and Lock Tool

9-5/8” Running Tool

9-5/8” Tieback Latch and Lock Tool

20” Mudline Casing Hanger 30” Landing Rig 13/38” Mudline Casing Hanger

9-5/8” Mudline Casing Hanger

RUNNING MODE

TIEBACK MODE

113


11.8.3 Slimhole Mudline System for Jack-up Drilling

30” x 1.00” Wall RL. 4LH Pin

13-38” Running Tool 20” MLC Casing Hanger 9-5/8” Running Tool 7” Running Tool 13-38” Casing Hanger Clamp 9-5/8” Casing Hanger 7” Casing Hanger Landing Joint

Split Centraliser

30" x 20" x 13-3/8" x 9-5/8" Casing Program This is ideal for most jack-up drilled exploratory or development wells. MLC emphasizes simplicity and economy without sacrificing high pressure and hanging weight capacities. 114

BOP Stack

Features and Benefits - Generous washout ports in the running tool Ensures no cement contamination around the running tool to give reliable well suspension. Indication at the rig floor that the wash ports are exposed. -

All casing hangers have robust left-hand threads Allows for rapid operation and ease of removal at suspension.

-

13-3/8" and 9-5/8" casing hangers also have finer right-hand tieback threads Allows for careful makeup of permanent metal-to-metal seal in tieback/production applications.

-

Three metal-to-metal seal areas for running tool, corrosion cap and tieback tool on 13-3/8" and 9-5/8" hangers This gives a new seal area for each tool that is run into the hanger, hence giving maximum seal reliability.

-

Over-torque protection on all running, tieback tools and corrosion caps Protects the seal area from damage due to incorrect installation, giving maximum seal reliability.

-

Long lead in stab guidance

-

Maximizes thread and seal protection.

115


CHAPTER - 12

WELL CONTROL KICK It is defined as an influx or flow of formation fluid into the well-bore & can occur any time the formation fluid pressure is greater than the bottom hole pressure being exerted in the well bore. BLOWOUT It is an uncontrolled flow of formation fluid at the surface or sub surface from the well bore. A Blow-out is the result of an uncontrolled kick. PRIMARY WELL CONTROL During normal drilling operations the hydrostatic pressure of drilling fluid is greater than the pressure of the fluids in the formation. The maintenance of sufficient hydrostatic head exerted by drilling fluid to hold back the formation fluid pressure is termed as “Primary Well Control”. SECONDARY WELL CONTROL If due to any reason hydrostatic pressure in the well bore falls below the formation pressure, formation fluid may enter in the well bore & if so happens, the primary control may be temporarily lost and a proper use of blow out preventers & kill procedures will provide Secondary well control, or in other words secondary well control involves detection & safe handling of kicks so as to re-establish primary well control. TERTIARY WELL CONTROL It involves the techniques used to control a blow-out once the primary & Secondary Control are lost. This primarily involves a re-establishment of the secondary control system such as : the well bore conduit, well head & BOP equipment & subsequently establishing the Primary Control. 12.1 CAUSES OF KICKS Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure which causes fluid to flow from the formation into the well bore. The main factors which can lead to this condition can be classified as : a) Improper hole fill up on trips. b) Swabbing. c) Abnormal formation pressure. d) Insufficient mud density. e) Lost circulation. f) Gas cut mud More than 50% of the kicks occur due to first two of the causes listed above. a) Improper hole fill up on trips When the drill string is pulled out of the hole, the mud level decreases by a volume equivalent to the steel volume. If the hole does not take the calculated volume of mud, it is assumed a formation fluid has entered the wellbore. Even though gas or salt water entered the hole, the 116

Well Control

well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure. Therefore, while pulling out the well should be filled continuously by using trip tank and differences of calculated and actual mud volume be recorded at regular interval. Similarly while running in drill string, trip tank should be used to monitor displacement volume correctly at regular intervals. If the hole is not filled to replace the steel volume, the fluid column in the wellbore shall go down and reduce the hydrostatic pressure. At the same time the pulling out of drill string causes a reduction in BHP due to swabbing effect. Therefore to avoid the possibility of any formation fluid entering the bore hole due to combination of above two factors the hole should be properly / regularly filled during tripping out. In the field normally the practice is to fill up the hole either on a regular fill up schedule or to fill up continuously with a re-circulating trip tank. Irrespective of the practice being used an accurate method of measuring the amount of fluid actually being taken by hole should be monitored and an accurate record of actual volume v/s theoretical volume should be kept. If at any stage during pulling-out it is observed that the actual filled in volume is significantly less than volume of steel that has been removed, it means that some formation fluids must have entered the wellbore. b) Swabbing Swab pressures are created by pulling out the drill string from the borehole. It reduces the bottom hole pressure. If the reduced bottom hole pressure becomes less than the formation pressure, a potential kick may enter the well bore. Various factors conducive to swab pressures are pipe pulling speed, mud properties, filtration cake, annular clearance, hole configuration and effect of balling up of BHA & bit. c) Abnormal pressure In case of wild cat or exploratory drilling, most often the formation pressures are not known accurately. While drilling, sometimes the bit suddenly penetrates an abnormal pressure formation. As a result the mud hydrostatic pressure becomes less than the formation pressure and may cause a well kick. There are various geological reasons for abnormal pressures. d) Insufficient mud density If a formation is drilled using a mud density that exerts less hydrostatic pressure than the pore pressure, the formation fluid may begin to flow into the well bore. Kicks caused by insufficient mud density seem to have the obvious solution of drilling with high mud density. The best solution is to maintain the mud density slightly greater than that required to balance the formation pressure in order to avoid mud loss. e) Lost circulation Lost circulation is another factor which reduces the hydrostatic pressure. When a kick occurs due to lost circulation, the problem may become more severe. A large volume of kick fluid may enter the hole before the mud level increase is observed at the surface. It is a recommended practice to keep the annulus always topped to avoid considerable reduction in BHP when lost circulation is encountered. 117


f)

Gas cut mud Gas contaminated mud will occasionally cause a kick. As the gas is circulated to the surface, it expands and reduces the hydrostatic pressure sufficient to allow a kick to enter. Although the mud density is reduced considerably at the surface, the hydrostatic pressure is not reduced significantly since the most gas expansion occurs near surface & not at the bottom.

12.2 KICK INDICATION Following are the early warning signs & positive indications for kicks while drilling. A. Early warning signs The detection of increasing formation or pore pressure is very essential in maintaining primary control of a well and preventing a kick. The early warning signs are indications of approaching higher formation pressure which means that the well may go under-balance if no appropriate action is taken. They are listed below : i)

Rate of Penetration Trends When abnormal pressure formations are encountered, differential pressure & shale density are decreased causing a gradual increase in ROP. An increase in drilling rate can be masked by an increase in mud weight. Similarly bit weight changes can also mask the increase in drilling rate but careful observation of drilling rate or some such related parameter as “d” exponent can provide a timely warning of increasing pressure.

ii) Drilling Break The first indication of a possible well kick is a drilling break. For reservoir fluid to enter the well bore there must be a permeable section of reservoir rock. This will cause a change in drilling rate. In soft formation, a sand section usually causes a sudden increase in drilling rate. The increase in drilling rate varies. A 200% to 300% increase in drilling rate is not unusual. In hard formations a reverse drilling break to a slower drilling rate occurs in the reservoir like sandstone that are harder than the shale body. iii) Increase in Torque & Drag As the difference between the mud hydrostatic pressure and formation pressure decreases (as a result of increasing formation pressure), the bit makes larger cuttings and the cuttings pile up around the collars and increase the rotary torque. Closing up of the hole may also increase torque. Increase in rotary torque is a good indication of increasing pressure and a potential well kick. Drag & fill up on connections and trips increase when high pressure formations are drilled. iv) Decrease in Shale Density Shale density usually increases with depth but decreases in abnormal pressure zones. The density of cuttings can be determined at surface and plotted against depth. A normal trend line is established and any deviation should theoretically indicate changes in pore pressure. v) Change in Cutting Size and Shapes Cuttings from normal pressure shale are small in size with rounded edges and are generally flat. Cuttings drilled from abnormal pressured formation often become long and splintery with angular edges. As differential pressure is reduced due to increase in formation pressure, the

118

Well Control

cuttings have a tendency to explode off bottom. A change in cutting shape will be observed along with an increase in the amount of cuttings recovered at the surface and this could indicate that formation pressure in the well is increasing. vi) Change in Mud Property As the pressure in the formation increases faster than the pressure of the mud column, more cuttings & cavings will dissolve into the mud and increase the viscosity of the mud. vii) Increase in Chloride Content in Mud Filtrate Drilling through high pressure formations having higher porosity results in contamination of drilling fluid with considerable volume of saline water from pores. This increases chloride content of the drilling fluid and its filtrate. A higher chloride trend can warn about increasing pore pressure. viii)Increase in Flow Line Temperature The temperature gradient in abnormal pressure formation is usually higher than normal pressure formation. The continuous measurement of the mud temperature at the flow line gives an indication of change in temperature gradient associated with abnormally pressured formation. The temperature may take a sharp increase (5-7oF/100 ft.) in transition zones. ix) Increase in Trip, Connection and Back-ground Gas An increase in trip and / or connection gas should be considered as an indication that pore pressure is increasing. Gas readings are arbitrary and are not proportional to actual gas concentration in the mud. These vary considerably from one mud logging unit to another. Therefore absolute values of gas readings do not have much significance in detecting abnormal pressures. Increase in back ground gas is not very reliable in detecting pore pressure increase. This is because gas concentrations can change drastically in the formation being drilled without any increase in pore pressure.Gas analyzers are used to establish trend line which is called background gas. A gas feed in from a permeable zone will change this trend line. The amount of feed in will determine the intensity of the trend change. Connection gas will normally occur on bottoms-up (calculated lag time) and if not re-circulated will not change the overall trend line except for short interval of time. The most common error with gas cutting is the tendency to maintain the mud weight at its original value with addition of barite and without removing all the gas. Since moderate gas cutting contributes so little to bottom hole pressure reduction, additional barite may increase the mud weight enough to cause lost circulation. x) Change in ‘d’-exponent Jordan and Shirley developed an equation for normalized penetration rate in which it was defined as a function of measured drilling rate, weight on bit, bit size and rotary speed in the equation as below: d Where, R N W Db

= log (R/60N)/log (12W/103 Db) = = = =

rate of penetration in ft/hr rotary speed rpm weight on bit in 1000 lbs bit diameter in inches

Since the d-exponent tends to indicate the pressure differential between formation pressure and well bore pressure, mud weight will effect d -exponent. The original calculation should be corrected as follows: 119


dc = where, dc = MW1 = MW2 =

d× (MW1 ÷ MW2 ) modified d-exponent mud density equivalent of formation fluid at normal pressure condition mud density being used in well

dc values are plotted on a semi log graph paper at every 15 or 30 ft. interval depth to give normal trend line. Abnormal pressure transition zone top is detected at the depth where dc exponent values against shale tend to decrease in comparison to normal values. B. Positive Kick Sign Positive kick indicators are different from kick warning signs. They indicate that the kick has already entered the well bore. Any of them indicate regular flow checks. i)

Increase in Return Flow (Pumps On) After the early warning signs the first positive kick sign is increase in flow rate at the flow line withpumps on. The entrance of any fluid into the well bore causes the flow rate to increase.

ii) Flow from Well (Pumps Off) Stopping the pump causes a reduction in bottom hole pressure equivalent to the annular pressure drop, so flow check is a reliable method of checking for a well kick. If the well does not flow when the pump is shut off and remains static for two or three minutes, then no well kick is entering. iii) Pit Volume Increase An increase in pit volume is obvious & positive indication of flow into the well bore & can be easily verified. If an increase in pit volume is seen, shut off the pump and make a flow check. If the well does not flow, no kick is entering. iv) Decrease in Pump Pressure and Increase in Pump Stroke In case of kick there is under balanced condition between the fluid in the drill pipe and the mixed column of mud and influx in the annulus. Therefore circulating pressure gradually decreases and unless the pump throttle is changed, pump speed slowly increases. 12.3 KICK WHILE TRIPPING When the pump is switched off, a reduction in BHP equal to annular pressure losses occurs. To prevent kick while tripping, basic requirement is that hole must be kept full of mud and the volume of mud required to fill the hole must be equal to the steel displacement of drill string pulled out. The sequence of events to a kick while making a trip-out of hole is : • Hole remains full or does not take proper amount of mud. Whenever such situation is noticed the pipe should be run back to bottom and mud is circulated to clear the hole. • Flow from the flow line • Increase in pit volume The sequence of events leading to a kick while tripping-in the hole is: • The hole does not stop flowing during making connection between the stands • Increase in pit volume In order to avoid well kicks while tripping, trip schedule must be made and trip tank must be used to monitor the hole fill up (in case of tripping-out) and mud displacement (in case of tripping-in). 120

Well Control

12.4 TRIP MARGIN During pulling out, upward motion of the drill string in the borehole (which is assumed to be full of mud) creates a swab pressure. This decreases BHP when pipe is in motion. One way of minimising this is to use safe tripping speeds and having close monitoring of pipe volume pulled out & mud volume pumped in to keep the hole full. Another practice to tackle the problem is to keep mud weight gradient greater than the formation pressure gradient. The resulting overbalance permits safe tripping and connection operations. This extra mud weight is called trip margin. For normal drilling operation trip margin is kept 0.2 to 0.3 ppg. However, the swab pressure being a function of yield point (yp) of mud, trip margin can be calculated as follows:Trip margin (ppg)= 8.33Yp ÷ 98 (dh-dp) Where Yp = Yield point of mud in lbs/100 sq.ft Dh = Hole diameter in inches Dp = Pipe outside diameter in inches Effect of riser margin on maintaining bottom hole pressure In the event of riser getting accidentally disconnected due to vessel drive-off or riser failure etc. the bottom hole pressure shall be reduced due to loss of hydrostatic pressure as the riser mud column is replaced by sea water. To compensate this reduction in bottom hole pressure, some margin has to be added to the drilling mud density which is known as riser margin. Example: Water depth RKB to sea level Mud density Seawater density Well TVD

-

700 ft 50 ft 11 ppg 8.5 ppg 10000 ft

Solution : RISER MARGIN (ppg) = [ Air Gap + Water depth] x Mud density – [ Water Depth x Sea Water Density] ———————————————————————————————————— TVD – Air Gap – Water Depth [ 50 + 700] x 11 – [ 700 x 8.5] —————————————— = 0.25 ppg 10000 – 50 – 700 Mud Density including Riser margin = 11+0.25 = 11.25 ppg 12.5 SLOW CIRCULATION RATE During well control operations, to avoid further entry of formation fluid it is essential to keep BHP minimum equal to formation pressure. This is done by imposing certain calculated back pressure in addition to system pressure losses on the well bore as long as old mud is in the well. Kicks have to be circulated out at slow circulation rates to ensure that the sum of this back pressure and system losses does not exceed the rating of high pressure lines and other rig equipment. Various reasons for circulating out the kicks at slow circulation rates are :a) To ensure that the slow circulation pressure plus the shut in drill pipe pressure is a convenient total pressure for the pump and does not exceed the surface line ratings. 121


b) To allow mud returns to be weighted up and re-circulated within the capabilities of available mud mixing system. c) To allow longer reaction time for choke adjustments. d) To allow sufficient time for disposal of kick fluid /de-gassing at the surface. e) To reduce the annular pressure losses. The common practice so far had been to select a rate which is about half the pump speed at the time of drilling. This practice was fairly good with duplex mud pump earlier in use on drilling rigs. Now with the use of triplex pumps this convention gives much higher speeds than the actual requirements. Theoretically speaking the kill rate or slow circulation rate should be the minimum possible pump speed at which pump can run smoothly without any knocking etc. But since at minimum pump speeds more time will be required to kill the well, a compromise has to be made which can meet all the requirements. Therefore slow circulation rate should be 1/2 to 1/3 of pump SPM at the time of drilling. Recording of slow circulation rate It should be recorded near to the bottom for each pump at regular intervals and / or when drilling conditions change such as:i) At the beginning of each shift. ii) After change in drilling fluid density. iii) After change in bit nozzle size or BHA. iv) After drilling a long section of hole (500 ft.) in a shift. v) After pump fluid end repair. On the rig there are a no. of places where drill pipe pressure gauges are installed such as stand pipe, mud pumps, driller’s console, choke & kill manifold and remote choke panel. Slow circulation pressure should be recorded from the gauge that is to be used for well killing operation . So, it should be recorded at remote choke panel, if available on the rig. Choke line friction losses In subsea operations when circulating through choke, flow resistance in the extending choke line running up from the sub sea BOP to surface is considerable. If pressure losses in choke line are not taken into account during well killing, an excess pressure unnecessarily may be applied in the hole. Since fracture gradient generally decreases with increased water depth, so beyond 500ft water depth choke line friction losses should always be considered while planning well control operations. Measurement of chokes line friction losses There are three ways to find out choke line friction losses.These are : a) Pump down the choke line at slow circulation rate taking the returns into the riser through open blow out preventer. The pressure thus shown on the choke manifold gauge is the choke line friction losses. The value so obtained does include circulating pressure losses in the riser but that is negligible. b) Record circulating pressure at slow rate through riser with BOP open. Close BOP, open choke line fail safe valve and record pressure with full choke open. The difference of the two values is the choke line friction loss. c) Pump down the choke line at slow circulation rate taking the returns through kill line with BOP closed. The pressure thus shown on the choke manifold gauge is twice the choke line friction losses. 122

Well Control

Corrected choke line friction losses for new mud density can be calculated as follows:New mud density Choke line friction losses with old mud × -———————— Old mud density Drill pipe pressure should be recorded at two or more slow circulation rates. Choke line pressure should also be measured over the same range of rates. Both drill pipe pressure & choke line pressure losses can be plotted separately on Log-Log paper and extrapolated to provide respective estimated pressure losses at various pump rates because due to high friction losses in the choke line it may be necessary to circulate out a kick at a very slow rate if formation breakdown is to be avoided. 12.6 LINE UP FOR SHUT IN When one or more positive kick signs are observed, flow check is made. In case of self flow well can be shut-in in two ways: a) Soft shut-in b) Hard shut-in 12.7 SHUT IN PROCEDURES As per API RP 59 As per following are the shut-in procedures for land/jack-up rigs & floating rigs. MGS

a) Line up for soft shut-in : Manual choke

Distribution Block Drilling Spool

B U F F E R To

HCR HCR Manual valve

Bleed/Vent Line

Remote choke Fig. 1 Shale shaker

LINE-UP FOR SOFT SHUT-IN Choke line manual valve HCR Line between HCR & Choke Remote choke Line from choke to MGS

: : : : :

Open Close Open Open (partially) Open 123

T Waste pit A N K


b) Line up for hard shut-in :

MGS Manual choke

Distribution Block

Drilling Spool

B U F F E R

HCR Valve HCR

Bleed/Vent Line

T A N K

To Waste Pit

Remote choke Shale shaker Fig. 2

LINE-UP FOR HARD SHUT-IN Choke line manual valve HCR Line between HCR & Choke Remote choke Line from choke to MGS

: : : : :

Open Close Open Open (partially) Open

12.7.1 While Drilling on Land and Jack Up Rigs a) Stop rotary. b) Pick up kelly to clear tool joint above rotary table. c) Stop mud pump, check for self flow. If yes, close the well as follows Sl.No.

Soft Shut In

Hard Shut In

i)

Open hydraulic control valve (HCR valve) / manual valve on choke line.

Close Blow Out Preventer (Preferably Annular Preventer)

ii)


Open HCR / manual valve on choke line when choke is in fully closed position.

iii)

Gradually close adjustable choke, monitoring casing pressure.

Allow pressure to stabilise and record SIDPP, SICP and Pit Gain.

iv)

Allow the pressure to stabilise and record SIDPP, SICP and Pit gain.

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Well Control

12.7.2 While Tripping on Land and Jack Up Rig a) Position tool joint above rotary table and set pipe on slips. b) Install full opening safety valve (FOSV) in open position & close it. Following methods are recommended for shut in the well. Sl.No.

Soft Shut In

Hard Shut In

i)

Open HCR Valve / Manual valve on choke line.

Close Blow Out preventer (Preferably Annular Preventer)

ii)


Open choke line HCR valve with choke is fully closed position.

iii)

Gradually close adjustable choke, monitoring casing pressure.

Make up kelly and open FOSV

iv)

Make up kelly and open FOSV

Allow pressure to stabilise and record SIDPP, SICP and Pit gain.

v)

Allow the pressure to stabilise and record SIDPP, SICP and Gain.

12.7.3 While String is Out of Hole on Land and Jack Up Rig (Soft Shut In) a) Open HCR valve on choke line. b) Close shear or blind ram. c) Close choke. d) Record SICP and pit gain. Note : In case of hard shut-in the sequence at a) & b) above shall be interchanged. 12.7.4 While Drilling on Floating Rig (Sub-sea) a) Stop rotary table. b) Raise kelly to hang off point ensuring that lower kelly cock is above rotary table and kelly is at the pre-designated level so that tool joint is clear of ram preventers. c) Stop mud pump, check self flow. If yes, proceed further to shut in the well. d) Close annular BOP (Preferably upper annular) e) Open fail safe valve on choke line when remote choke is in close position. f) Close the upper pipe rams. g) Reduce hydraulic pressure on annular, hang the string and ensure rams are locked. h) Open annular after bleeding trapped pressure between annular and pipe ram. i) Record SIDPP, SICP and Pit Gain. If motion compensator is not working or not reliable, following steps should be followed after step e) : i) Set slips and close lower kelly cock. Bleed off stand pipe pressure and break away kelly above kelly cock. ii) Pick up circulating head make up the same above lower kelly cock, pick up the string to hang off point and remove slips. iii) Close the upper pipe rams. iv) Reduce hydraulic pressure on annular hang the string and ensure rams are locked. v) Open annular BOP after bleeding trapped pressure between annular and pipe ram. vi) Open Lower kelly cock. 125


vii) Record SIDPP, SICP and Pit Gain. 12.7.5 While Tripping on Floating Rig (Sub-sea) i) Set slips below tool joint. ii) Install full open safety valve (FOSV) in open position, close it & remove slips. iii) Open Fail-safe valve on choke line when remote choke is in close position. iv) Close annular BOP. v) Calculate the length of the pup joint and /or length of stick up above rotary table to ensure that the tool joint is clear off the pipe ram to be closed. vi) Make up kelly & open FOSV. vii) Close upper pipe rams. Reduce operating pressure on annular BOP. viii) Lower drill string & hang it off on the rams. Open Annular BOP after bleeding pressure. ix) Record SIDPP, SICP and pit gain. 12.7.6 When String is Out of Hole or Above the BOP on Floating Rig (Sub-sea) a) Open fail safe valve on choke line when choke is in close position. b) Close blind shear ram. c) Record shut-in pressure & pit gain. 12.8 SHUT IN PRESSURE INTERPRETATION A. Shut-in Drill Pipe Pressure (SIDPP) The shut in pressure on the drill string side is the difference between the hydrostatic pressure of drilling fluid and the formation fluid pressure. When a kick enters during drilling, the drill string remains uncontaminated whereas annulus becomes contaminated with influx. If SIDPP is added to hydrostatic pressure of drilling fluid, the resultant pressure will be the pressure of the formation. SIDPP is used to determine the kill mud weight required to balance the formation pressure by using the equation given below SIDPP(psi) Kill Mud Density (ppg) = —————————— + Original Mud Density(ppg) 0.052 × Well TVD( ft) The shut in drill pipe pressure should be read & recorded from the gauge on the choke control panel. Since true SIDPP is determined for the calculation of kill mud density, it is recommended to read and record the SIDPP immediately after the closure and subsequently after every 3-5 minutes. The recorded values of SIDPP should be tabulated/plotted to ascertain the true value of SIDPP. Once the well is closed initially the SIDPP starts increasing till the BHP becomes equal to the formation pressure. The time taken for stabilisation depends upon the permeability of the formation. SIDPP may further increase but at a slower rate if the influx is gas/gas mixture. B. Shut-in Casing Pressure (SICP) The shut in pressure on the annulus side is the difference between the combined fluid hydrostatic pressures and formation fluid pressure. Since annulus is contaminated with formation fluid (Oil, gas, salt water or combinations) therefore SICP can not be used to calculate kill mud density however it is used to determine kind of influx which has entered the well bore. During kill operation casing pressure will allow us to determine the pressure being exerted at various points in the well bore and also pressures on the BOP equipment and choke lines. 126

Well Control

Example A well was shut in after a kick, given below are the tabulated values of SIDPP and SICP. Find out the stabilized value of SIDPP. Time

SIDPP(psi)

SICP(psi)

0600

100

150

0605

200

270

0610

275

370

0615

340

450

0620

400

520

0625

405

525

0630

415

535

0635

430

550

0640

450

570

Note : Pressure recording should be done at every two minutes interval. Solution As evident from tabulated values, SICP is increasing faster than SIDPP up-to 0620 hrs but later both the pressures are rising by same amount. This shows that the pressures have stabilised at 0620 hrs and subsequently due to close well gas migration both the pressures are rising by same amount. Therefore the value recorded at 0620 hrs i.e. 400 psi is the true SIDPP. The proper recognition of stabilised value of SIDPP is very important as this value is used for the calculation of kill mud weight and formation pressure. Example A well was shut in after a kick, given below are the tabulated values of SIDPP and SICP. Find out the stabilised value of SIDPP. Time

SIDPP(psi)

SICP(psi)

0800

150

200

0815

250

320

0830

340

420

0845

420

510

0900

500

600

0915

500

600

1000

500

600

1100

500

600

1115

505

605

1130

510

610

1145

520

620

127


Solution As is evident from tabulated values, SIDPP and SICP were increasing considerably up to 0900 hrs & later there is no change in the pressures up to 1100 hrs Therefore the value recorded at 0900 hrs i.e. 500 psi is the stabilised value of SIDPP. Further increase in both the pressures is due to closed well gas migration. 12.9 WELL KILLING PROCEDURE The main principle involved in all well killing methods is to keep bottom hole pressure constant. The various kill methods are as follows: 1) Driller’s Method 2) Wait and Weight Method 3) Volumetric Method In the first three methods the influx is circulated out and the heavy mud is pumped in the well keeping the bottom hole pressure constant. The fourth method i.e. Volumetric method is a non circulating method in which the influx is brought out & heavy mud is placed in the well bore without circulation. Bringing the pump to kill speed on land / jack up rig It is important to understand the start up procedure, irrespective of kill method, for bringing the pump up to kill speed. Pump should be brought to kill speed patiently. During this period if the casing pressure is allowed to increase it can cause formation breakdown or if the casing pressure is allowed to decrease it can cause entry of more influx into well bore. To prevent this, following procedure is suggested. a) Bring the pump to kill speed slowly holding casing pressure constant by manipulating choke. b) When the pump is at the desired kill speed follow the pressure schedule according to the kill method being used. Note : While bringing the pump to kill speed keeping casing pressure constant, there might be slight reduction in bottom hole pressure due to expansion of gas but this is compensated by the annular pressure losses. 12.9.1 Driller’s Method In Driller’s method the killing of a well is accomplished in two circulations • In first circulation the influx is removed from the well bore using original mud density. • In second circulation the kill mud replaces the original mud and restores the primary control of the well. Formulae Required SIDPP (psi) a) Kill Mud Weight (ppg) = Old Mud Weight + ———————0.052 × TVD (ft) (ppg) b) Initial Circulating Pressure (ICP) = SIDPP(psi) + KRP (psi) 128

Well Control

Kill mud weight (ppg) c) Final Circulating Pressure (FCP) = ———————————— × KRP(psi) Original mud weight (ppg)

d) Surface to Bit Strokes

=

Drill string volume (bbl) ————————————— Pump output (bbl/stroke)

e) Bit to Shoe Strokes

=

Open hole annulus volume (bbl) —————————————— Pump output (bbl/stroke)

f)

=

Annulus volume (bbl) ————————————— Pump output (bbl/stroke)

Bit to Surface Strokes

Killing Procedure (Drillers Method) In this method the well is killed in two circulations. •

First Circulation a) Bring the pump up to kill speed in steps of 5 SPM, gradually opening the choke holding casing pressure constant. b) When the pump is up to kill speed, maintain drill pipe pressure constant. c) Circulate out the influx from the well maintaining drill pipe pressure constant. d) When the influx is out, stop the pump reducing the pump speed in steps of 5 SPM, gradually closing the choke, maintaining casing pressure constant. Record pressure, SIDPP and SICP should be equal to original SIDPP.

Note : In case recorded SIDPP & SICP are equal but more than original SIDPP value, it indicates trapped pressure in well bore. Whereas if SICP is more than original SIDPP, it indicates that some influx is still in the well bore. •

Second Circulation a) Line up suction with kill mud. b) Bring the pump up to kill speed in steps of 5 SPM, gradually opening the choke, holding casing pressure constant. c) When the pump is at kill speed, pump kill mud from surface to bit, maintaining casing pressure constant. d) Pump kill mud from bit to surface, maintaining drill pipe pressure constant equal to FCP. e) When the kill mud reaches surface, stop the pump reducing the pump in steps of 5 SPM, gradually closing the choke maintaining casing pressure constant. Record pressures, SIDPP and SICP both should be equal to zero. Open & observe the well. Add trip margin before resuming normal operation.

129


Fig. 3. Pressure Profile- 1st Cycle of Driller’s Method A-B

Casing pressure rises as influx expands in drill collar annulus.

B-C

Casing pressure decreases as influx crosses over from drill collar annulus to drill pipe annulus & losses height.

C-D

Casing pressure again rises as influx now expands in drill pipe annulus and it becomes maximum when influx reaches surface at point ‘D’ on the graph.

D-E

Casing pressure reduces sharply as influx is removed from the wellbore.

Drill Pipe Pressure Graph I-J Drill pipe pressure is held constant till the influx is removed from the well bore.

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Well Control

Fig. 4. Pressure Profile- 2nd Cycle of Driller’s Method Casing Pressure Graph F-G Casing pressure is held constant till kill mud is pumped from surface to bit. G-H Casing pressure reduces to zero as kill mud is pumped from bit to surface. Drill Pipe Graph L-M Drill pipe pressure reduces as kill mud is pumped from surface to bit. During this period SIDPP drops & becomes zero whereas KRP increases to FCP value. On the whole drill pipe pressure reduces from ICP to FCP. M-N Drill pipe pressure is held constant as the kill mud is pumped from bit to surface.

12.9.2 Wait and Weight Method • •

In Wait and Weight method well is killed in one circulation using kill mud. In this method operations are delayed (wait) once the well is shut in, while a sufficient volume of kill (weight) mud is being prepared. As the kill mud moves from surface to the bit the hydrostatic pressure in the Drill Pipe increases, this causes the drill pipe pressure to fall. At the same time, influx which is on its way up the annulus expands continuously and gains volume / height, thereby causing the hydrostatic pressure in annulus to fall and casing pressure to rise. Because of this, for maintaining BHP constant a calculated step down plan for the drill pipe pressure must be used while pumping the kill mud from surface to the bit. 131


Formulae required SIDPP (psi) a) Kill Mud Weight (ppg) = Old Mud Weight + ———————(ppg) 0.052 × TVD (ft) b) Initial Circulating Pressure (ICP) = SIDPP(psi) + KRP (psi) Kill mud weight (ppg) c) Final Circulating Pressure (FCP) = ————————————— × KRP(psi) Original mud weight (ppg) d) Surface to bit Strokes

=

Drill string volume (bbl) ——————————— Pump output (bbl/stroke)

e) Bit to shoe Strokes

=

Open hole annulus volume (bbl) —————————————— Pump output (bbl/stroke)

f)

=

Annulus Volume (bbl) ———————————— Pump output (bbl/strokes)

Bit to surface Strokes

ICP – FCP g) Pressure drop / 100 strokes = —————————— × 100 Surface to bit strokes Killing Procedure (Wait and Weight Method) a) Line up suction with kill mud. b) Bring the pump up to kill speed in steps of 5 SPM, gradually opening the choke, holding casing pressure constant. c) When the pump is at kill speed, pump kill mud from surface to bit, maintaining drill pipe pressure as per step down schedule (during this step drill pipe pressure will fall from ICP to FCP). d) Pump kill mud from bit to surface, maintaining drill pipe pressure constant equal to FCP. e) When the kill mud reaches surface, stop the pump reducing the pump speed in steps of 5 SPM, gradually closing the choke maintaining casing pressure constant. Record pressures, SIDPP and SICP both should be equal to zero. Open & observe the well. Add trip margin before resuming normal operation. COMPARISON OF METHODS Driller’s Method Advantages

Disadvantages

1.

Simple to understand

Higher annulus pressure

2.

Minimum calculations

Higher casing shoe pressure in gas kick.

3.

In case of salt water kick, sand settling around BHA is minimum.

Minimum two circulations are required. More time on choke operation.

132

Well Control

Wait and Weight Method Advantages

Disadvantages

1.

Lower annulus pressure.

High non circulating time.

2.

Lower casing shoe pressure when open hole volume is more than string volume.

In case of salt water kick, sand settling around BHA is maximum.

3.

Well can be killed in one circulation.

Calculations are more.

4.

Less time on choke operation.

More chances of gas migration.

Fig. 5. Pressure Profile- Wait & Weight Method Casing Pressure Graph A-B Casing pressure rises as influx expands in drill collar annulus. B-C Casing pressure decreases as influx crosses over from drill collar annulus to drill pipe annulus & losses height. C-D Casing pressure again rises as influx now expands in drill pipe annulus. D-E Casing pressure continues to increase but initially at a slower rate as at this stage kill mud starts entering the annulus, later on casing pressure increases at a faster due to rapid expansion of gas. E-F Casing pressure reduces sharply as influx is removed from the well bore. F-G Casing pressure further reduces as original mud is replaced by kill mud. Drill Pipe Pressure Graph H-I Drill pipe reduces from ICP to FCP as kill mud is pumped from surface to bit. I- J Drill pipe pressure is held constant at FCP as kill mud is pumped from bit to surface.

133


12.9.3 Volumetric Method of Well Control The volumetric method is a non circulating killing method used for removing gas influx when there is little or no drill pipe in the hole, a wash out in the string or when the hole can not be circulated. It works equally well for a situation where the well is closed-in and waiting on orders or equipment or for stripping in or out of hole. In this method the influx is brought up to the surface by means of migration & controlled expansion. This process involves bleeding of calculated volume of mud at the surface till the influx reaches the surface, thereby allowing the casing pressure to increase to maintain BHP constant. After the gas influx is brought to the surface in this manner of controlled expansion, the calculated volume of mud is pumped in to the well & gas influx is bled thereby allowing the casing pressure to decrease while maintaining BHP constant. The basis of the volumetric method is that each barrel of mud contributes a certain pressure to the bottom of the hole. This may be measured as psi/bbl. This term of psi/bbl must be co-ordinated with pit volume or trip tank volume so that the number of barrels can be read directly. A record of casing pressure is kept, if the casing pressure rises mud can be bled from the well according to the psi/bbl value calculated to maintain a constant bottom hole pressure. The volumetric method works by bleeding off (or adding) mud because the BHP is the sum of the casing pressure & the pressure exerted by the mud column. The Volumetric method of well control should not be equated with classic well killing methods. Volumetric method is used to control BHP within limits by co-ordinating the increase (because of gas migration) or decrease (because of bleeding of gas ) in annulus surface pressure with the corresponding decrease or increase in annular hydrostatic pressure (by decreasing or increasing height / weight of mud column in the annulus). Volumetric method is implemented mainly in two steps namely the “bleeding” and “lubrication” process. In the bleeding process the gas influx is allowed to migrate in the annulus and thereby causing an increase in the annular surface pressure as well as the BHP. The goal of maintaining the BHP constant is achieved through corresponding reduction in annular hydrostatic pressure by bleeding calculated volume of mud which in turns reduces the mud column height in the annulus and allows the gas to expand. The bleeding process has to be repeated several times till the gas reaches the surface. Once the gas is at the surface the process of lubrication starts. In lubrication process annular hydrostatic pressure is increased by injecting a calculated volume of same or heavy mud through kill line while the BHP is maintained constant by bleeding gas through choke and reducing surface pressure by the same amount. The process may be repeated several times till all the gas influx is fully removed from the annulus and the annular surface pressure is brought down to zero or at a level wherein tripping /stripping of the bit to the bottom or removing/ replacing of choked or damaged string becomes feasible. Once the bit is at the bottom, the well can be killed / circulated with appropriate kill weight mud. Volumetric Kill Calculations Example Well TVD Influx Mud weight Annular volume SICP SIDPP

= = = = = =

10,000 ft 20 bbl 10.0 ppg 0.047 bbl/ft (8 1/2” × 5”) 500 psi 0 psi 134

Well Control

As indicated by SIDPP value (0 psi) the bit nozzles are plugged, therefore the well has to be killed by Volumetric method. Calculations a) For Bleeding Process Let the incremental increase in casing pressure would be 100 psi Mud Gradient = 0.052 × 10 = 0.52 psi/ft Height of mud column for 1 psi of Hydrostatic pressure = 1 /0.52 ft Height of mud column for 100 psi of Hydrostatic pressure = 100 / 0.52 ft = 194 ft Volume of Mud for 100 psi hydrostatic pressure = 194 × 0.047 = 9.04 bbl b) For Lubrication Process Calculation of kill mud weight for lubrication SIDPP KMW = OMW + ————— 0.52 × TVD As the SIDPP may not be known SICP may be taken in place of SIDPP. But if the value of SICP is very high then SIDPP can be calculated by assuming some gas gradient by the following formula :SICP – SIDPP Influx gradient = Mud Weight × 0.052 – ———————— Height of influx Since kill mud is to be placed only in the top section of the well which is being occupied by gas, the height of gas column is to be calculated. Total pit gain = Initial pit gain + Total amount of mud bled = 20 bbl + 100 bbl (say) = 120 bbl 120 Height of gas column when gas is at the surface = ——— = 2553 ft 0.047 500 KMW = 10 + —————— = 13.76 ppg 0.52 × 2553 Kill mud gradient = 13.76 × 0.052 = 0.715 psi/ft Height of kill mud column for 1 psi of Hydrostatic pressure = 1 / 0.715 ft Height of kill mud column for 100 psi of Hydrostatic pressure 100 / 0.7155 = 139.76ft Volume of kill Mud for 100 psi hydrostatic pressure = 139.76 × 0.047 = 6.57 bbl Killing Procedure (Volumetric Method) Volumetric killing is accomplished in two steps, namely ‘Bleeding’ & ‘Lubrication’. 1. Bleeding a) Allow the casing pressure to increase to 650 psi, this causes the BHP to increase by 150 psi, don’t start bleeding now (this 150 psi may be kept as safety margin). 135


b) Allow the Casing pressure to increase by another 100 psi to 750 psi, this causes the BHP to increase by 250psi. Since it is planned to keep only 150 psi extra pressure at the bottom as safety margin, we can now reduce 100 psi of BHP by bleeding 9.04 bbl of mud. While bleeding mud the surface casing pressure should not be allowed to reduce more then 100 psi which may require the bleeding to be completed in number of steps. c) Allow the pressure to increase by another 100 psi to 850 psi and bleed 9.04 bbl of mud in the same way. d) This procedure should be repeated until gas reaches surface. Thereafter, Lubrication technique is to be used for reducing the casing pressure.

1100 C A 1000 S I 900 N G 800 P R E S S

Bleeding is continued until gas is at top

700 600

Safety margin 150 psi Initial SICP 500 psi

500 9.04

18.08

27.12

36.16

45.20

54.24

63.28

Volume of mud bled off from annulus (bbl) Fig. 6. Mud Bleeding Process

2. Lubrication The lubrication technique is used to Kill the well / reduce the casing pressure when gas is at the surface so that other operation such as tripping / stripping can be performed. 1. Slowly pump the calculated volume of mud (6.57 bbl) which shall give 100 psi equivalent hydrostatic pressure into the annulus. Allow the mud to fall through the gas. This is a slow process, but can be speeded up by using a low yield point mud. 2. Bleed gas from the annulus until the surface pressure is reduced by 100 psi or the amount equal to the hydrostatic pressure of the mud pumped in. In no case mud is to be bled off. 3. Repeat the process until all of the gas has been bled off and the well is killed or the desired surface pressure is reached. Note : During the pumping and gas bleeding process, it will usually be necessary to decrease the volume of mud pumped before gas is bled off particularly near the end of the operation. This is because the annular volume occupied by the gas decreases with each pump & bleed sequence. Watch the pumping pressure closely and when it reaches 50-100 psi above the shut in casing pressure, stop pumping. Measure the volume of mud pumped, calculate the hydrostatic pressure of that volume in the annulus and bleed sufficient gas to drop the casing pressure by the amount of hydrostatic pressure plus any increment of trapped pressure because of pumping operation. 136

Well Control

Volume and Pressures during Top Kill (Assuming maximum surface pressure of 1900 psi at the end of bleeding operation) Volume to lubricate, bbl (cumulative) 0 6.57 13.14 19.71 26.28 32.85 39.42 45.99 52.56 59.13 65.70 72.27 78.84 85.41 91.98 98.55 105.12 111.69 118.26 124.83

Pressure to Bleed (psi)

Remaining casing pressure (psi)

0 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100

1900 1800 1700 1600 1500 1400 1300 1200 1100 1000 900 800 700 600 500 400 300 200 100 0

12.10 SUB-SEA CONSIDERATIONS RELATED TO WELL KILLING Consideration of Choke Line Friction The effect of long choke lines can be very significant. The pressure loss is related to water depth, circulating rate, and internal diameter of choke and kill lines. The pressure loss effect of the choke line applies to all points in the well bore and is especially critical at shallow or weak casing seats. The problem can be handled by measuring the choke line friction pressure before drilling out of casing. The casing pressure could then be reduced by the amount of choke line friction pressure while bringing the pump to kill speed. The initial circulating pressure (SIDPP + Slow rate pressure through riser) will be approximately the same if the casing pressure is reduced by the amount of the choke line friction pressure. Choke line friction can be reduced by lowering slow circulation rate. Another way of lowering choke line pressure would be to utilize both choke and kill lines. Normally both lines are utilised specially towards the end of the kill operation. Pressure Changes When Gas Reaches Choke Line When gas reaches the choke line, the mud in choke line is quickly displaced out by gas causing a sharp reduction in hydrostatic pressure. This may cause sharp bottom hole pressure reduction if choke is not properly adjusted to establish the correct drill pipe pressure. When gas leaves the choke 137


line and is replaced with mud, another sharp fluctuation will take place and could result in over pressurizing the formation if not quickly adjusted to re-establish correct drill pipe pressure. Effect of Different Density Fluids in Choke & Kill Lines In deep water well killing, the displacement of one density fluid by another can cause sharp changes in the BHP. There can be rapid drop in BHP when gas displaces mud in the choke line, the situation is reversed when the trailing mud displaces gas in the choke line. If the choke does not respond equally fast then a second influx or formation breakdown may occur. This makes choke line displacement one of the most difficult stages of the well killing operation. Moreover, since there is rarely a sharp boundary between gas and mud, several severe and sharp changes in BHP and d/p pressure are encountered. As the capacity of choke line is very less, displacement even at kill rate gives very short time to make the adjustments on choke to keep the BHP constant. Some of the actions suggested to avoid sharp changes in BHP are: i) To displace the line at an extremely slow rate when gas top reaches the BOP stack. ii) Use a large diameter choke line. iii) Use both choke and kill line in parallel without changing the pump rate. 12.11 TOP HOLE DRILLING In upper part of the hole, drilling rate is normally too fast, hole sizes are large & porosity is very high. Cutting carrying capacity of the drilling fluid is poor since hole is about 30% to 40% larger than nominal size & high annular velocities can not be obtained. This leads to concentration of cuttings in the annulus thereby increasing the equivalent mud density in the annulus. Formation strength in the top hole section is normally low, more so in a marine well since part of the overburden there consists of seawater rather than formation. As such while drilling a top-hole section the chances of bulk mud losses are high, which if happens can lead to a shallow formation flows. The various problems faced while drilling top-hole section are as below: a) The formation being weak is vulnerable to bulk mud losses. b) Soft, fast drilling formation generates large volumes of cuttings that tend to accumulate in the bore hole. c) Annular velocity is very low (due to large hole) and top-hole mud has a poor cutting carrying capacity. d) Kicks occur quickly & since shallow reservoir can have high permeability, time for action is very limited. The shallow gas kicks are difficult to detect at an early stage because most of the standard flow detection techniques fail. Flow checks on drilling breaks become impractical as drilling rates generally are very fast & penetration rates vary tremendously. Mud volume is continuously being added to active mud system therefore pit level indicator at times can not be made use of. The only reliable indicator is differential flow sensor. On the other hand reaction time is minimal since gas expands almost immediately upon entering the well bore, which further reduces the hydrostatic head and allows more and more influx to enter the well bore. As such well can not be closed because flow might broach to the outside of the shallow casing. The major hazards of shallow gas influx i) It can lead to blow-out. ii) It can cause serious damage to the personnel, rig & equipment. 138

Well Control

iii) It can broach through outside of shallow casing leading to instability of bottom supported rigs. iv) Risk of crater, fire & loss of rig is very high. A typical approach to a shallow gas kick is to allow the well to flow through a diverter. The diverter system is designed to pack off around Kelly, casing or drill string. It does not shut in the well, but allows the flow to be diverted through a vent line to a safe distance away from the rig. Well is allowed to flow and simultaneously mud or water is pumped through the drill string at maximum rate to keep as much fluid in the well as possible. Either the well shall flow till the formation depletes (or annulus bridges) or the well is brought under control by increasing the mud weight. 12.11.1 Shallow Gas Control Procedure Diverter system should be used to control shallow gas kicks as discussed below. During Drilling a) At first sign of flow, immediately stop rotary, raise the kelly until tool joint is above rotary. b) Open diverter overboard line valves depending upon wind direction. c) Close diverter packer. d) Circulate out with available drilling fluid at maximum possible pump rate. e) Remove the non essential personnel from the rig. While a) b) c) d) e) f) g)

Tripping Set pipe on slips. Install FOSV and close it. Open diverter line valves depending upon wind direction. Close diverter packer. Connect Kelly or circulating head. Open FOSV. Circulate out with available drilling fluid at maximum possible pump rate. (Note : Step b and f are not required if string contains a float valve) h) Remove the non essential personnel from the rig.

Control of some critical drilling parameters Since shallow gas kicks occur quickly and time for action is limited, it is useful to control some critical drilling parameters to prevent shallow gas kicks. a) Penetration Rate:- The rate of drilling is normally very fast in top holes, it adds tones of drilled cuttings in the hole to create mud density much higher than what is required. It can lead to fracture of formations & bulk mud losses & therefore result in shallow gas influx. Thus there is need for limiting the actual penetration rates to a value less than that can be achieved. b) Mud Density:- Avoid mud density increase down hole by (i) Drilling large diameter holes in two stages (i.e. drilling a pilot hole) (ii) Circulating out the cuttings with viscous mud sweeps. c) Tripping:- Higher tripping speeds should be avoided, upper formations areusually sticky (more so in offshore) & has more tendency to ball the bit thus enhancing the probability of swabbing. If necessary the drill string should be pumped out of the hole to limit swabbing. Whenever the pilot hole has been drilled, hole enlargement with under reamer should be preferred as it can be collapsed before starting pulling out in order to reduce the swabbing effect. 139


In addition to above, following measures are suggested. i) Heavy Mud A minimum of one reserve mud tank weighing about 2-3 ppg more than the drilling mud should be kept reserve. ii) Mud Losses When ever losses are encountered, they should be sealed before drilling ahead. Bits should have large nozzles to allow pumping of LCM material. iii) Active Mud System & Flow Checks Mud pit volumes should be continuously monitored so as to detect any change in active mud volumes. Periodic flow checks should be made while drilling in potential gas zones. iv) Float Valve A float valve may be run in the string to prevent sudden flow through the drill pipe.

140

Down Hole Complications

CHAPTER - 13

DOWN HOLE COMPLICATIONS Complication is a problem in the well bore that prevents safe drilling, logging, casing lowering, cementation, production testing and completion of a well. Fishing is any operation or procedure to release, remove or recover tubular or any material left in the well bore that affects drilling, logging, casing lowering, cementation, production testing and well completion. Common types of drilling complications are: 1. Stuck up. 2. String failure. 3. Bit failure. 4. Casing failure. 5. Mud loss. 6. Well activity. 7. Cementation failure. 13.1 STUCK UP Stuck up occurs due to one of the following reasons: a) Differential sticking. b) Mechanical sticking. c) Key seating. d) Well bore instability. e) Mud loss. f) Cement sticking. a) DIFFERENTIAL STUCK UP As it is well known, no well is perfectly vertical. At all times the drill string is in contact with the well bore. Assuming the weight of the drilling assembly below a certain point is W & hole angle is á then the side force acting on the drill string which causes the string to press against the well bore is equal to W x sin α.. During drilling through a porous & permeable formation a thick mud cake is deposited on the side of the well bore due to filtrate loss into the well bore. During drilling or tripping, the string is lubricated by mud and the hydrostatic pressure acting on all sides of the string is equal. When the drill string is stationary the portion lying on one side of the well bore against a permeable & porous formation is isolated in such a way that the mud cake restricts pressure communication due to the seal. The pressure acting on the side in contact with the well bore is equal to the formation pressure whereas on the remaining side it is equal to the hydrostatic head of mud. The differential pressure so caused results in the string being pressed against the well bore and subsequently getting differentially stuck although circulation is normal. String cannot be rotated and movement of the string will be ceased. A force (F) equal to the net force exerted against the sealed area multiplied by the coefficient of friction is required to move the assembly to release the stuck pipe. Force F = P x A x C Where F = Force required to release the stuck pipe 141


P = Differential pressure = Hydrostatic head of mud column – Formation pressure A = Area of contact C = Friction factor (For sand it varies from 0.05 to 0.3) PREVENTION & REMEDIAL MEASURES z Minimize contact area of bottom hole assembly against well bore by running stabilizers and spiral drill collars in the hole. z Use the minimum length of the largest size of drill collars. z Drill with minimum overbalance to minimize differential pressure. z Maintain undesirable solids content as low as mechanically possible. z Maintain recommended mud properties relative to the formation being drilled, minimize water loss and cake thickness. z Maintain optimum hydraulics to remove cuttings from well bore. Loading of the annulus by cuttings increases the hydrostatic pressure and consequently the differential pressure. z Use controlled drilling rates especially in large size holes to avoid increase in mud weight in the annulus. z Run a drilling jar in the bottom hole assembly so that it can be activated as and when required. z Use lubricants in the mud to reduce friction factor. z In case of mechanical shut-down pull out the string inside shoe. If it is not possible, keep string under compression. Slack off at least the weight of the bottom hole assembly to keep it in buckling condition and thereby minimizing the contact area to reduce the chances of differential stuck up. z Never by pass the shale shaker screen during drilling, otherwise presence of cutting in the mud system will increase the mud weight. Clean the settling tank after each phase of drilling. Higher contents of drilled solids increases the viscosity, thereby increasing the water loss. This results in thicker filter cake and increases the chances of differential sticking. z Do not keep pipe stationary in open hole unless it is mechanically impossible to reciprocate/rotate the string. z While drilling with a premium bits perform a wiper trip frequently to prevent build up of filter cake in the previously drilled section of the hole. z Time is of greatest importance in releasing a differentially stuck pipe. From studies carried out in the laboratory by simulating actual field conditions it was found that it takes approximately 1 1/2 hr for the cake to dry out. Work the pipe within safe permissible limits during this period otherwise the force required to release the string may exceed tring capacity after the cake dries out (friction factor will become 1). PRIMARY METHOD OF RELEASING DIFFERENTIALLY STUCK PIPE z Reduce the pump strokes (do not stop the pump – general rule of thumb reduce the SPM to a third). z Work right hand torque to the stuck point & bump down. z If there is a drilling jar in the string, operate the down jar. z If there is no sump at the bottom work the pipe in tension (operate the up jar). z Never work the up jar with torsion in the string. z Always work within safe limits of the string. 142


SECONDARY METHODS OF RELEASING DIFFERENTIALLY STUCK PIPE (i) Spotting Pipe Lax Spotting is done against the stuck zone which penetrates the filter cake and breaks the seal formed due to the filter cake. Surfactants (2.5% to 3%) are added to the spotting fluid to reduce surface tension between contacting surfaces by creating a thin layer between the pipe and the mud cake. This reduces coefficient of friction thereby helping in mechanically releasing the pipe. z Find out the free point of the drill string. (Although a logging unit is preferred, it may not be readily available especially in wells drilled onshore. In such cases, Driller’s method of free point location may be used). z Calculate the volume of spotting fluid required such that the entire annulus from the stuck point to the bottom of the string is covered by the spotting fluid & the height of spotting fluid inside the drill string is 100 to 150m more than that of the annulus. z The annular volume should consider the caving factor assuming that the hole is not gauged. z It is a good practice to pump a high viscous pill ahead of the spotting fluid to reduce the chances of migration especially in wells where mud weights are high. z Pump the spotting fluid into the drill string and displace it by mud such that the height of spotting fluid inside the string is 100-150m more than in the annulus. This will ensure a back pressure on the spotting fluid reducing the chances of its migration during soaking period. (Migration of spotting fluid can be reduced if a weighted spotting fluid is prepared but an un weighted spotting is more effective than weighted spotting). z Work the pipe as the spotting fluid rises in the annulus. z After displacing the spotting fluid close the kelly cock or the stand pipe valve to prevent migration of fluid into the drill string. z The pipe is generally kept in compression during soaking period except in exceptional circumstances. In case of stuck drill string the minimum weight that should be slacked off is equal to the air weight of the assembly below the stuck point. z The soaking period is generally 8 hours but may vary according to operational requirements. z After the soaking period the string is worked vigorously. z If the string is not released then spotting fluid inside the drill string is displaced into the annulus in a phased manner at equal intervals (e.g. 100 liters every hour). The string is worked intermittently to try and release the string otherwise it is left in compression. z Before going for second spotting in case the stuck pipe is not released a free point location may be done to ascertain the effect of the first spotting. Note: In areas prone to differential sticking (like depleted horizons of Barial in Geleki field of Upper Assam), it is recommended that all arrangements for oil spotting are made in advance so that spotting can be done at the earliest after stuck up. The chances of releasing a stuck pipe are better if the spotting is done before the mud cake dries out completely i.e. within 1 ½ hour of stuck up. Also in areas where there are chances of well activity due to oil spotting a weighted spotted fluid may be used otherwise a non weighted spotted fluid is preferred. (ii) Spotting Mud Acid In cases where oil spotting is not found to be effective, before going for a time consuming and expensive fishing operation it is recommended to go for acid spotting. Acid spotting has been used to free stuck pipe in wells of Lakwa, Mehsana & Ahmedabad oil fields. The technique is similar to 143


that of oil spotting except that diesel is used as a spacer between acid and mud. Acid being corrosive, a suitable anti corrosive inhibitor is added to the acid to prevent corrosion of the string. Acid spotting is not done through the rotary hose or in case the fish is caught with an over shot as it corrodes the rotary hose & damages the seals of the over shot. z Find out the free point of the drill string. (Although a logging unit is preferred, it may not be readily available especially in wells drilled onshore. In such cases in normal wells driller’s method of free point location may be done). z Calculate the volume of acid required such that the entire annulus from the stuck point to the bottom of the string is covered by the acid & the height of acid inside the drill string is 100 to 150m more than that of the annulus. z The annular volume must consider the caving factor assuming that the hole is not gauged. z Pump a spacer of diesel such that it occupies a height of 50m of drill pipe inside volume. z Displace it by mud such that the height of acid inside the string is 100-150m more than in the annulus. This will ensure a back pressure on the acid reducing the chances of its migration during soaking period. z Work the pipe as the acid rises in the annulus. z After displacing the acid close the kelly cock or the stand pipe valve to prevent migration of acid into the drill string. z The pipe is generally kept in compression during soaking period except in exceptional circumstances. In case of stuck drill string the minimum weight that should be slacked off is equal to the air weight of the assembly below the stuck point. z The soaking period is generally 4 hours but may vary according to operational requirements. z After the soaking period the string is worked vigorously. z If the string is not released then the acid inside the drill string is displaced into the annulus in a phased manner at equal intervals. (e.g. 100 liters every hour). The string is worked intermittently to try and release the string otherwise it is left in compression. Note : Unlike diesel / crude oil spotting technique the spent acid once discarded into the cuttings pit is neutralized and hence is non-polluting. Since acid is corrosive and although its corrosive effect on drill string is controlled by using anti corrosive inhibitor, still it should not be pumped into the well using mud pumps and circulatin hose as it will corrode the rubber elements in the circulation system. Acid pumper should be used. If Kelly is connected at the time of stuck up, it should be backed off and string made up to surface. Line is to be made to the acid pumper. The other draw back is if the fish is caught by an over shot where as oil spotting can be done, acid spotting cannot be done. As in the case in Ahmedabad & Mehsana after back off, the fish was engaged by a matching pin and acid spotting could be done to release the stuck up. b) MECHANICAL STUCK UP (i) Hole pack off – improper hole cleaning The behavior of drilled cutting & cutting beds vary according to the angle of the well bore. The degree of difficulty of hole cleaning vs. the hole angle is as below. z Angle less than 30 deg. – vertical, least difficult to clean. z Angles between 30 deg. and 65 deg. – transitional, most difficult to clean. z Angles between 65 deg. and 90 deg. – horizontal, cutting beds are more stable but more difficult to clean than wells with angle less than 30 deg. 144


Factors affecting hole cleaning in wells less than 30 degrees z Mud weight. z Annular velocity. z Fluid reology & flow regime. z Cutting size, shape & quantity. z Pipe rotation & eccentricity. z Circulation time. Mud weight z It provides buoyancy to help lift the cuttings – better transport ratio. z It affects the momentum of the fluid. z It affects the friction the fluid can impart to the cuttings. z Higher the mud weight greater is the buoyancy & lesser is the slip velocity. z Frictions provides greater lift & drags the cuttings off the wall. Note: We do not increase the mud weight to improve hole cleaning as it can result in differential stuck up, poor ROP, poor log quality & poor productivity. Annular velocity z Second most important factor affecting hole cleaning. z Provides lifting force through momentum transfer & friction. z The lifting force is directly proportional to annular velocity in laminar flow. z The contribution of annular velocity depends on mud weight. – if mud weight was zero there would be no contribution to hole cleaning from annular velocity. Fluid reology & flow regime There are three flow regimes a) Laminar flow b) Turbulent flow c) Plug flow. z In laminar flow the flow regime is parabolic & heavier cuttings are pushed to the wall & subsequently fall back in the well. z The larger the cutting more is the force at which they are pushed to the wall & fall into the well – this results in cuttings recycling. z Turbulent flow better hole cleaning as it has a flatter flow profile – however turbulence increases hole erosion & may also result in mud loss. z Yield point (YP) contributes to good cleaning efficiency. Plastic viscosity (PV) does not. z Higher YP / PV ratio provides a flatter profile. z Efficient hole cleaning can be provided with a laminar flow if the YP / PV ratio is high without causing hole erosion / mud loss. Cutting size, shape & quantity z Slip velocity increases with size & density of cuttings and if the cuttings are more spherical. z Large quantity of cuttings interferes with each other & flow profile reducing the cleaning effect. z This results in the flow profile becoming more parabolic & cuttings stick to the wall. z Drilled solids also increase the PV. 145


Rate of penetration z Controls the size & quantity of cuttings. z Higher the ROP more is the hole cleaning efficiency to be improved. z Drill only as fast as the cuttings can be removed. z Loading of the annulus with drilled cuttings will result in hole pack off / plugged nozzles. Pipe rotation & eccentricity z Pipe rotation improves the cuttings transport ratio – better hole cleaning. z Pipe eccentricity (pipe sticking to the wall) reduces the transport ration – poor hole cleaning. Time z

If sufficient time is not given to circulate out the cutting prior to tripping it can result in stuck pipe.

Factors affecting hole cleaning in high angle wells > 30 deg z Hole inclination. z Flow rates. z Mud properties & flow regimes. z Cutting beds. z ROP. z Pipe rotation & eccentricity. z Time. Hole inclination z Angle 0 to 30 deg. – Vertical z 30 to 65 deg. – Transitional z 65 – 90 deg. – horizontal. z As the angle increases to 30 deg. the cuttings migrate to the wall. z The re-cycling of cuttings is more severe as the angle is greater than 30 deg. z As the angle approaches 45 deg. The time cuttings spend on the wall greatly increase. z In the transitional angles the cutting beds are always unstable. z At angles between 45 & 65 deg. the cuttings slide down even while circulating. z At angles above 65 deg. cuttings form beds but are more packed but harder to disturb. z Sliding of cuttings is more with OBM than WBM. Cutting transport mechanisms z Suspension z Bed transport z In vertical sections the cuttings are well mixed with the drilling fluid. z As the angle increases they tend to migrate to the low side and move up in a heterogeneous section. z At higher angles they form beds and roll on the side of the well z At 65 deg the beds are stationary unless disturbed by pipe movement z Homogenous suspension is the most efficient method of cutting transport. z Cutting rolling or bed transport is the least efficient.

146

Down Hole Complications z

z

z z z z z z z z z z z z

The hardest to clean is the 30 – 65 deg section because the cutting tend to slide and are unstable even with circulation. In the horizontal section the cutting will be transported as a heterogeneous suspension above the cutting beds. Laminar flow is desirable in vertical sections Turbulent flow in angles greater than 55 deg. Most challenging is the 45 – 55 deg section. Mud properties As angle increases the effect of mud weight is less. It slows the boycott settling effect. It has same effect on momentum transfer The cutting con. Increases drastically between 35 – 45 deg at low MW. Cutting bed height is substantially reduced with slight increase in MW. Sliding of cuttings is reduced at higher MW. Cutting beds are more fluidized in heavier mud and more easily disturbed The minimum velocity needed to initiate cutting rolling is less with heavier mud. An increase in mw makes it easier to erode the cutting beds.

Yield point and plastic viscosity In directional wells an increase in YP generally has a detrimental effect on hole cleaning because: z Higher viscous mud cannot penetrate the cutting beds as easily as low viscous mud. z It also distorts the flow profile. z Intermediate viscosity mud perform the best at any angle and at all laminar flow rates when pipe eccentricity exits. z Height of cutting beds decrease a viscosity reduces Conclusions z Water in turbulent flow provides the best hole cleaning in angles more than 65 deg. z In absence of pipe rotation cutting beds are always present z Cutting beds do not exist in turbulent flow. z Change in reology has less effect when pipe is rotating z Pipe rotation is required more with high vis. mud than with low vis. mud. Flow rates z Annular velocity is the most important factor in hole cleaning of high angle wells. z Annular velocity that prevents cuttings deposition is desired. z This will result in very high flow rates and surface pressures. z In absence of pipe rotation there will always will be cutting deposition z Cutting beds slide more with OBM than WBM. Cutting and cuttings beds z Are formed during low or no pipe rotation z When BHA is pulled through these sections they form a hill and pile up around stabilisers. z When the bed is small we experience drag. z When it is high it causes pack off.

147

Drilling Operation Practices Manual z z z z z z z z

At low angles cutting are recycled on the low side of the well but they are heterogeneous and no beds are formed. At moderate angles cutting beds are formed on the low side and easily disturbed. In higher angles of inclination cuttings beds are well packed and tend to be stationary Rate of penetration. Has no effect in high angle wells. It has no effect on bed height. As more cuttings are generated they are transported above the bed height. Pipe rotation and other methods are required to disturb the cutting beds.

Pipe rotation and eccentricity z Has significant effect in high angle wells z It affects the flow profile z At high angles the reduction of velocity in the low side of the well greatly hampers the cutting transport. z At high angles the pipe is lying in the low side of the well bore. z At higher viscosities we need to rotate at higher rpm than at low viscosities. z Smaller the cuttings more is the effect of pipe rotation z Rotation cannot handle large cuttings at higher ROP. Time z z z

It takes more time to transport cuttings along an inclined well bore than a vertical well. Circulation stroke factors (CSF). CSF or no. of bottoms up to clean hole. Inclination

27 1/2”

17 1/2”

12 1/4”

8 1/2”

0-30 30-65

2.25 2.75

1.75 2.5

1.5 1.75

1.25 1.5

65+

3

2

1.75

3

Preventive measures z Maintain adequate flow rates specially in high angle wells z Rule of thumb for vertical wells – annular velocity should be twice the cuttings settling rate. z If pumping out of hole circulate with same or more discharge as was being done during drilling. z It is a good practice to wash last few stands to bottom. z Control the rate of penetration. z Stop drilling when hole conditions dictate. z Plan wiper trips z Circulate cuttings out prior to tripping out and away from the bha prior to connection. z Maintain a high YP / PV ratio z Use high viscous pill sweeps for vertical wells. z Use low, high viscous pills sweep combination for high angle wells z Minimise connection time z Establish over-pull limits. z Pulling too hard into a pack off will prevent the pipe from being freed downward z Use small increments of over-pull. 148

Down Hole Complications z z z z z z z

Ensure the pipe is free in at least one direction. Monitor drilling trends. Record the free rotating weights, pick up weight, slack off weight, off bottom & on bottom torque and circulating pressure. Early warning signs are the best way to stay to stay out trouble. Evaluate torque and drag trends and rate of cutting removal. Back ream carefully at high angle wells. Record all tight spots

Warning signs z Insufficient cuttings return for the rate of penetration. z Erratic returns. z More solids coming out of the shaker than being drilled. z An increase in PV, viscosity, mud weight out, sand content, or low gravity solids. Connection trends z Increase in over-pull over slips and a pressure surge to start circulation. z Increase in pump pressure to break circulation. Drilling trends z A linear increase in pump pressure. z Erractic pump pressure. z Increase in both torque and drag. Tripping trends z Swabbing. z String pistoning during pumping out. z Excessive or erratic drag. Primary freeing procedure First action - Bleed off pressure and apply 200- 500 psi to try to establish circulation. z Apply torque and slack off. z Jar down if jars are in the string. z Generally the string packs off during trip out z In high angle wells it can get packed off during trip in – jar up in this case. z Jar with incremental increase in trip load. z If bit is bottom work up ward with low pressure. Secondary freeing procedure z Pulling hard –not the first choice. z Only done when ever thing else fails. z The driller must know the maximum amount of over-pull. z Ensure that there is no torsion in the string while working or jarring upward. z Sometimes we can pump the string out of the hole again not first choice. z The above pistons the assembly harder into the pack-off. 149


Fishing procedure z Backoff above free point & wash over. z Carefully select the length of the wash over pipe. z Wash over pipe tend to get differentially stuck. z After wash over run a fishing assembly with both up & down fishing jars. (ii) Hole pack off - formation instabilty Formation like shale and coal is subjected to caving Excessive caving may form a bridge leading to mechanical stuck up and cease of circulation. Due to presence of caving in the annulus, torque and drag increases. If proper care is not taken about the drag, it may lead to shearing of drill string. While making connection under caving hole condition, the bit may be set into the caving while trying to get the kelly drive bushing into the rotary. This could cause the drilling assembly to get stuck or plug the bit resulting in another trip to unplug it. Well bore instability is caused by 1. Hydro Pressured Shale: It account for a vast majority of stuck pipe. Most important factor that contributes to shale becoming unstable or remaining unstable is mud. Mud type, density & reology are of critical importance. If mud filtrate invasion into the well bore takes place, the hole condition will deteriorate. Prevention & remedial measures z Provide adequate support by gradually increasing mud density. z Minimize the exposure of the troublesome formation by faster drilling and casing the section. z Select the minimum number of stabilizers to drill this section as for as possible. Reaming or back reaming is likely to disturb the bore hole and is to be done very carefully. z Pressure surges by tripping too fast are to be minimized. Tripping through the troublesome zone should be done slowly so as to minimize swab & surge pressures. In case of stuck pipe z Work on pipe to establish circulation and try to release the string by giving pull within the safe margin. z If the pipe cannot be released by working with circulation, back off above the free point. z Wash over and recover the fish left in the hole. Washing over should utilize a heavier mud weight than was used during drilling. z During wash over if sticking of the wash over pipe is being observed; pull out the wash over pipe. Put cement plug above the fish top & side track the fish. 2. Loose / Unconsolidated Formations: These are found at shallow depth and usually comprise of loose sand, gravel or its conglomerate. These formations may slough in the well without warningwhile drilling. Seepage & partial loss may aggravate the situation. Indications z Drilling of loose uncemented sand, gravel or conglomerates in top hole. Observing excessive amount of loose solids coming over the shale shaker and being discharged from desander and/or desilter. 150

Down Hole Complications z z

Erratic drag / over pull after connections. Tendency for hole to pack-off. Experiencing seepage or partial loss.

Note : Previous experience of drilling in the area along with information provided in the G.T.O. will provide valuable information in this regard. Prevention & remedial measures z Drive or grout the conductor as deep as practically possible. z Avoid planning a kick off in these formations. z Use efficient hole cleaning practices. Sweep the hole regularly with high viscous pills. z As this phenomena is time dependent, drill through the troublesome section with optimum rate of penetration with out compromising on hole cleaning. z There are two options available. If the entire loose unconsolidated section has been drilled through, case the problematic interval. If there remains a portion of the interval yet to be drilled and if there are chances of pipe sticking, place cement plug against this interval. Cement will provide reinforcement and may be required to be done as often as necessary to allow total penetration of the interval. z Use large size nozzles during drilling of loose unconsolidated formations to reduce the stand pipe pressure. z Avoid pressure surges during tripping and break circulation carefully. z Include a jar in the string, its position being above the troublesome formation. Recovery of drill string stuck in loose unconsolidated formation Once the pipe gets stuck in unstable formation, the recovery can prove difficult. Washing over a fish left in the hole after back off may not be viable option as the chances of wash over pipe getting stuck are great. Only option remaining is set a cement plug above the fish and side track the hole. 3. Fractured & or Faulted Formations: Formations like limestone, chalk or shale can be naturally fractured and / or run along fault line(s). If the horizontal stress distribution is unfavorable, the well bore will destabilize resulting in large pieces of formation dislodged from the well bore. If the circulation rate is unable to lift these cuttings, hole pack off will occur. If the instability is on account of severe losses, it is crucial to take immediate action to cure it. The string should be pulled above fractured zones. Before going in hole, attempts should be made to control losses. Ream back to bottom cautiously and sweep the hole at regular intervals. Indications z Large pieces of cuttings or dislodged formation observed over the shale shaker during the drilling phase. It will restrict circulation and could ultimately result in a complete pack-off of the annulus. z Erratic drag, over pull and fill after connections, particularly during loss situation. Erratic torque and vibration when drilling ahead. z Reaming during or after wiper trip/round trips. Prevention & remedial measures z Reduce the exposure of the fractured/faulted interval by preventing the bit from drilling along the dipping formations. This will reduce the tendency to become unstable. Select the BHA so as to maintain required angle through the fault/fracture. 151

Drilling Operation Practices Manual z z z z z

Use the mud motors to reduce the whipping action of the drill pipe to prevent caving . Use large size nozzles during drilling of fractured formations to reduce the stand pipe pressure. Pull out the string upto the problematic zone before situation deteriorates. Ream back cautiously if needed. Spend additional time to circulate the hole clean. Use low / high viscosity sweeps as required. If mud loss is significant, attempt to cure before drilling ahead.

Recovery of drill string stuck in fractured/faulted formations z Work on pipe to establish circulation and try to release the string by giving pull within the safe margin. z If the pipe cannot be released by working with circulation, back off above the free point. z Wash over and recover the fish left in the hole. Washing over should utilize a heavier mud weight than was used during drilling when the pipe got stuck. z During wash over if sticking of the wash over pipe is being observed; pull out the wash over pipe. Put cement plug above the fish top & side track the fish. 4. Mobile Formations: Drilling of plastic salts or shales, which have a tendency to deform plastically or creep into the hole, will have the potential to reduce the hole clearance. The hole may become under gauged during the drilling phase or when the string is pulled above the zone. Salts or shales which have the tendency to be mobile must be highlighted in the planning and preparation phase. Indications z Mobile salts or shales mentioned in the G.T.O. although an accurate prognosis remains difficult. z Tight pull while pulling out BHA across plastic salt or shale zone. z High and erratic torque while reaming to bottom after a wiper trip or round trip. z No significant change in the circulating pressure. Prevention & remedial measures z Trip & ream cautiously to avoid a sudden increase in over pull and torque respectively. z Plan wiper trips carefully. z Place the drilling jar preferably above the troublesome zone. z Maintain the mud properties as specified. z Consider use of bi-centre bits. z Consider use of saturated salt based mud while drilling through salt sections. Saturated salt in the mud will prevent dissolution of formation salt into the mud there by to prevent hole enlargement & hole instability. Recovery of drill string stuck in mobile formation z If the pipe is stuck due to salt creep, perforating and circulating fresh water will often dissolve the salt and allow for recovery of pipe. z Time is of great significance. The longer the pipe is allowed to remain stuck by salt creep, the longer will be the length of stuck pipe. z Standard wash over is also possible so long as fresh water flushing is done to prevent further creep in of the salt. 152


5. Geo–pressured formations: These formations are commonly shales in a pressure transition zone. If the pore pressure prediction of is inaccurate and hydrostatic pressure exerted by the mud column is less than pore pressure, it is likely to result in hole instability that is recognized by distinctly splintery, spalled fragments of shale. Emphasis is on accurate pore pressure prediction and the same is be to included in the G.T.O for monitoring during the course of drilling. Indications z During the drilling phase, the cavings are likely to cause an increase in torque, drag and over pull. z Distinctive splintery and spalled cavings, which should not be confused with cavings coming out from shallower zones. Cavings can be small in size in the initial stage. z The presence of cavings is usually accompanied by increasing levels of background gas, trip gas & higher R.O.P. z If these indications are ignored, bridging and hole pack off will occur. Prevention & remedial measures z Emphasis is to be given on pore pressure prediction based on seismic data, offset well data, geological correlation etc prior to incorporation in the G.T.O. This data is to be supplemented with the data available during the drilling phase like R.O.P. back ground gas & trip gas. z Keep watch on the amount of pressure induced by cavings and the return flow. z Gradually increase the mud density, if it is confirmed that cavings are due to geo –pressure. Monitor for the effect of the mud density increase. z Reduce the time spent on activities with no circulation (e.g. round tripping, logging, BOP testing etc). z Avoid excessive swab & surge pressure. z Optimize hole cleaning. Recovery of drill string stuck in geo-pressured formation z Back off & wash over is the recommended procedure for recovery of fish. z Depending on the thickness of the section, and the rate of deformation, consideration should be given to the length of fish washed over in the first attempt. z Use heavier mud weight while washing over. z Recovery of the fish may be in parts if the entire length of fish cannot be washed over in one attempt. In such a case after every recovery prove the hole with a bit and stabilise well conditions prior to further wash over. 6. Tectonically Stressed Formations: Tectonically stressed formations have unusually high horizontal stresses in one or more directions that can result in sedimentary rocks being fractured or squeezed. If the rock fails, block size cavings can fall around the drill string resulting in stuck pipe. This can also result in key seat formations preventing the pulling out of B.H.A. / bit. Indications z Significant problems during running in and pulling out. z Large block size cavings on the shale shaker. z Increase in stand pipe pressure indicating hole pack off. 153

Drilling Operation Practices Manual z z

Erratic drag during drilling and while making connections. If the location is in a mountainous area offset well data, rock mechanical data with the seismic data can be used to assess the severity of tectonic stresses.

Prevention & remedial measures z Optimize of well path based on best available prognosis. z If the original hole turns out to problematic, sidetrack immediately selecting a more favorable well path. z Increase the mud density to the maximum possible. However this might not have the desired effect or might not be possible if other zones are exposed. z Plan to case the hole section as soon as practically possible. Include contingency hole size/ casing in the drilling program. Recovery of drill string stuck in geo-technomic formation z Back off wash over is the recommended procedure for recovery of fish. z Depending on the thickness of the section, and the rate of deformation, consideration should be given to the length of fish washed over in the first attempt. z Use heavier mud weight while washing over. z Recovery of the fish may be in parts if the entire length of fish cannot be washed over in one attempt. In such a case after every recovery prove the hole with a bit and stabilise well conditions prior to further wash over. 7. Reactive Formations: Formations that fall under this category are relatively young shales (sloughing shales) that react to untreated water. The invasion of untreated water causes hydration stress resulting in cracks and swelling of the shales. Attempts should be made to reduce water invasion and subsequent hydration, by using inhibitors like salts (K, Na or Ca), or polyglycols. Indications z An increase in PV, YP and MBT mud reology parameters. Cuttings will be mushy and if not dispersed sufficiently might cause clay balls to reach the flow line. z During roundtrips, bit/ BHA will get balled up with clay causing over pull and/or swabbing. z Increase of pump pressure, torque and drag are also possible particularly in larger size holes. Prevention & remedial measures z Ensure timely inhibition with salts (K, Na or Ca). Coating polymers like PHPA & Soltex will also reduce water invasion. z Maintain the specified mud properties. If necessary, dump and dilute, but without excessive sacrifice to inhibition. z Ream and perform wiper trips in the interval where over pulls are encountered. Always break circulation slowly & carefully after trips. z Minimize exposure time in open hole. z When running in with stiff B.H.A. take extra caution when wiping or reaming the hole. Recovery of drill string stuck in reactive formation (sloughing shale) z Thoroughly condition the mud so as to maintain inhibited properties. z Try to recover the fish by washing over and if fails go for side tracking. 154


(iii) Well Bore Geometry Mechanical stuck due to well bore geometry is due to the conflict between the shape of the BHA and shape of the well bore, usually no restriction in circulation. Reasons for sticking due to well bore geometry: a) Doglegs b) Ledges c) Squeezing formations d) Under gauge holes a) Doglegs Majority of well bore related sticking is due to doglegs. Doglegs result in: z Key seats z Ledges z High side loads z Torque z Poor cementation of casing z Trouble running casing & logs z String failure, production equipment failure, casing wear during drilling Key seats z Rotating drill pipe against a dogleg cuts a slot in the formation which is smaller than the BHA. z While tripping out the drill pipe can pass but the larger and stiffer BHA cannot. z Factors affecting key seat formation. z There must be dog leg for a key seat. z A side force is necessary z Pipe must be rotating & rotating long enough. z Hardness of the formation at the dog leg z In vertical wells the shallower the key seat the more troublesome it will become. z In horizontal wells although a huge dog leg is created it does not create troublesome key seats because the side load is less. z The string is usually in compression while rotating through the dog leg. When to expect key seats z High side loads. z Long rotating hours. z High side loads exists when the dog leg is at a shallow depth. z Rotating off bottom creates more tension at the dogleg. z Crooked hole country with hard & soft inter-bedding. z Warning signs: z Increase in torque and drag during drilling. z Cyclic drag during tripping – as the tool joints pass through the key-seat. z Interval of over-pull spikes at 30’ interval. z In longer key-seats the number of tool in this interval will provide cyclic drag. 155

Drilling Operation Practices Manual z z z z z z z z z z

The most indicative of the key-seat presence is increase in over-pull in subsequent over-pull. In the same interval of the key-seat tripping in is not a problem Prevention of stuck pipe due to key-seats: Avoid sharp doglegs specially high in the well. Ream and wipe out doglegs when suspected. Install a key-seat wiper in the string. Avoid rotating off bottom. Driller must be aware where his BHA is with respect to well bore geometry. Pull slowly when BHA is passing the keyseat. Use greater length of HWDP so as to have more set down weight.

Freeing procedure for key-seats z Jar in the opposite direction the pipe was moving before it got stuck. z Since all stuck up in key seats takes place during trip out – apply torque and jar down. z Once free down ward back ream out z Secondary freeing procedures for key seats z If string is not free by down jarring or surface jarring then: z Back off above the key-seat and run in with fishing jars. z If the key-seat is in a carbonate formation -try an acid pill. z Spot a lubricating pill. z Low frequency resonance tool may knock the pipe out the key-seat Secondary freeing procedures for key seats If string is not free by down jarring or surface jarring then z Back off above the key-seat and run in with fishing jars. z If the key-seat is in a carbonate formation try an acid pill. z Spot a lubricating pill. z Low frequency resonance tool may knock the pipe out the key-seat. Stiff assembly sticking z Occurs when a stiff BHA jams into the dogleg. z Casing being stiff this type should be anticipated past build sections or doglegs. Warning signs z Sudden set down weight as the BHA enters a dogleg. z Tripping in with a stiffer BHA. z High torque when rotating into a dog leg. z Wear on stabilisers or part of the BHA. z High torque and drag during pull out z Prevention of stuck pipe due to stiff assembly z Limit dog leg severity. z Take totco frequently. z BHA changes to be minimised. z Minimise the set down weight in doglegs. z Ream the dogleg section. z Be always aware where the BHA is with respect to dogleg section. 156


Freeing procedures z Jar in the opposite direction the pipe was moving prior to getting stuck. z While jarring up never apply torque. Secondary freeing procedure z A spotting fluid is placed to reduce friction. z Acid pills in carbonates. z Wire line resonance tools. z Back off and run fishing jars Micro doglegs or crooked hole z Are caused by directional changes or natural drilling tendencies in soft hard alterations. z A number of micro dogleg together cause excessive trouble z They reduce the effective diameter of the well. z When the stiff BHA is in tension it cannot pass the reduced diameter. z Pipe usually gets stuck while picking up. z Stiffer assemblies and casing can get stuck while moving down. z High dipping formations Warning signs z Fluctuating ROP. z Increase in torque & drag while picking up. z Increasing torque while drilling z Trend of bottom & off bottom torque. z Making several directional changes or sliding with motor Prevention of micro deg leg sticking z Minimise directional changes. z Avoid high WOB with slicker BHA. z Frequent back reaming will wear the rough edges of the micro doglegs. z Driller must be aware where the BHA is with respect to the doglegs. Freeing procedure z Jar in the opposite direction the pipe was moving prior to sticking. z Spot lubricants, spotting agents, acid in carbonates. z Low frequency resonance tools. b) Ledges z Mainly caused in inter-bedded formation z Harder formation in gauge , softer formation washed out z Doglegs can lead to ledges. z Also form around factures & faults. z They give trouble when running casing. z Stabiliser blades can also hang up on ledges. When to expect ledges z Hard & soft inter bedding – leads to bit walk. 157

Drilling Operation Practices Manual z z z

Fractured & faulted formation. Graded salt where salt dissolves at different rates. Any type of dog leg

Warning signs z Fluctuating rate of penetration z Cyclic over pull during trip out z Sudden & erratic over pull at the stabiliser blades or bit hits a ledge. z Sudden set down of casing or drill string. z Known inter bedding, fractures, or faults Prevention z Prevent doglegs. z Use better mud program to prevent hole enlargement – inhibitive mud. z Care during tripping. z · Ream troublesome ledges. Freeing procedure z Jar with light strokes initially to prevent fall of loose formation. z If assembly going down is free, then rotate past the ledges while trip out. z If the casing is stuck going down upward motion may be free and the casing may be rotated to bottom. z Acid pills in carbonate formations c) Squeezing Formations z Commonly salts, marls, plastic shale. z Squeezing is caused by overburden, tectonic forces, or hydration swelling. z No problem drilling, but during trip out the stab. & bit wedge into lesser diameter. z Salt is very plastic. Factors affecting salt deformation or creep z Overburden and tectonic stresses. z Purity and thickness of salt. z Temperature. z Mud weight and mud type Warning signs z Presence of salt or coal. z A lack of cuttings. z Increase in chloride concentration. z Increase in ROP. z Increase in torque & drag Prevention z Avoiding the salt or creeping formation. z Raise mud weight. 158

Down Hole Complications z z z

Use salt based mud. Regular reaming of the salt interval. Bi-center bits.

Freeing procedure z Jar in the opposite direction the string was moving prior to sticking. z A fresh water pill can be spotted to dissolve salt d) Under gauge hole z Due to under gauge bit or stabilisers. z Drilling of abrasive formation. z Running built up stabilisers. z Plastic formations. Warning signs z Poor ROP due to bit wear. z In case of salts ROP increases. Prevention of stuck up due to under gauge hole z Care while tripping. z Ream any under gauge hole intervals. z Always check the gauge of all tools going in and out of the hole. Freeing procedure z Jar up when the pipe is stuck going in. z Acid pills. z Spotting fluids. 13.2 OTHER CAUSES OF STUCK UP 13.2.1 Mud Loss Lost circulation is the loss of borehole mud to the exposed formations in the well and may result in stuck pipe. Mud flowing into the formation implies that there is less mud return at the flow line than is being pumped or that there is total loss of circulation. The reduction in the annular velocity of the mud in the zone above the loss zone reduces the carrying capacity of the mud. Cuttings may accumulate in the low velocity region and may fall back into the bottom of the hole resulting in stuck pipe due hole pack off. The drop in level of mud in annulus causes a reduction in hydrostatic head and may lead to lesser wall support of an exposed shale section causing sloughing. This will further deteriorate the well bore stability and may cause the pipe to get stuck against the shale section also. The reduction in hydrostatic pressure against a permeable formation may result in well bore influx. A situation in a well where there is mud loss, hole pack off and well bore influx is extremely hazardous, time consuming and expensive. Prevention & remedial measures The measures to be taken to control the mud loss will depend on whether the loss is a surface seepage loss, partial loss or total loss against natural factures, loss due cavernous and vugular formation or induced losses. To prevent pipe from getting stuck due to mud loss the following is suggested: 159

Drilling Operation Practices Manual z z z z

z z

z z

z

z

z z

z

z

z z z

z

All potential loss zones are to be indicated in the G.T.O. Adequate stock of loss control material is to be maintained at site. The flow fill line indicator must be installed prior to spudding the well. This will help to take remedial measures as soon as well bore starts to take mud. Always use drilling jar in mud loss prone area while drilling. A properly placed drilling jar will not only help in releasing a stuck string but also help in regaining circulation in case of hole pack off. The string must be pulled inside casing shoe and keep the annulus full. The decision to place loss control material against the loss zone prior to pulling out will depend on the severity of the loss, whether the hole is sloughing or not and whether the loss also results in well activity.. In case of activity the primary task is to shut in the well immediately. Is case the loss does not result in well activity but causes hole sloughing, the pull out the string inside casing shoe keeping the annulus full. In case of partial loss which does not result in well bore instability or well activity a loss control material should be pumped into the well. In areas known for mud loss drilling must be done using larger size nozzles, with minimum number of stabilizers/reamers. Minimum numbers of the largest size drill collars are to be used in this section of the hole. Drill the loss control zone with a minimum mud weight and optimum discharge. In case the loss is in the larger diameter of the hole (>121/4”) the feasibility of drilling a pilot hole with reduced discharge and large size nozzles is to be worked out. Control of loss in smaller hole sizes is much easier. A provision for another contingency string of casing or drilling liner is to be made if severe loss is expected. Provide extra storage to ensure sufficient mud supply. Adequate supply of technical water is to made in advance in loss prone areas. Minimize the surge pressure during tripping and while breaking gel after tripping in the hole. Loss of circulation can occur against any weak zone in the open hole. In case the loss is not severe or is due to surface seepage, allow the well to cure by resting without circulation with the bit inside casing shoe. Feasibility of drilling the loss zone using gas, air, foam, or aerated mud or if hole conditions permit, dry drilling are to be worked out.

13.2.2 Cement Sticking During placing a cement plug in open hole by a balanced plug. While setting a balanced cement plug, cement is pumped through a string of drill pipe or tubing. Cement is displaced for a pre-determined length into the string annulus and some is also left inside the pipe so that as the pipe is pulled out, the cement inside fills the pipe displacement, leaving a clean uncontaminated plug in the well. The cement is designed based on hole conditions and should be retarded or accelerated as required. The potential danger lies in the unlikely chance of flash set causing the string to be cemented in the hole. Identification z Unable to reverse circulate. z Unable to pull out the cementing string. 160


Immediate action z Pull to the maximum safe limit of the string. z Attempt to circulate at a higher pressure than that available with rig pumps ( use cementing unit). Preventive action z Technical water should be tested for designing cement slurry. z Simulate down hole conditions prior to cement job. z Make all arrangements for reversing out in advance. z Cementing units and mud pumps should be checked prior to taking up cementing job. z Contamination of the cement with mud should be prevented by using spacers. Recovery process z Back off and wash over the cemented string. z During a cement squeeze job using a packer. Even when a packer is utilized for a squeeze job, several problems may result in cementing the pipe in the hole. z The packer can leak. z The casing being squeezed can leak from a point above the packer setting depth. Both these instances can lead to the string getting stuck above the packer identification: If a pressure gauge is installed on the annulus of the cementing string, it allows close monitoring. Should there be leak occur, anywhere, the pressure in the annulus will indicate it. Immediate action z If there is any pressure change which indicates cement is entering the annulus of the cementing string. The squeeze operation should be stopped immediately. Unseat the packer and reverse out the cement in the annulus. z Recovery process z If the pipe is cemented in place inside a casing the following will decide the recovery techniques to be followed: The length of the cemented section. The depth at which the pipe is cemented. The strength of the cement bond. The annular clearance between the cementing string and the casing. Except in large size casings, the annular clearance between the cemented string and the casing rules out wash over as a means of recovery. One option, depending on techno economics, is to mill out the cemented string. Another option is sidetrack from above the stuck pipe or plug and abandon. Preventive action While carrying out a squeeze job using a open end string is to place a balanced cement plug. Pull the string above the cement plug. Reverse out 11/2 times the annular volume and then squeeze. z While using a packer to squeeze monitor the annulus pressure. Any build up of pressure will indicate a leaking packer. Stop the squeeze job. Unseat the packer and reverse out the annulus volume.

161


13.3 STRING FAILURE: The main causes of drill string failure are: a. Fatigue failure. b. Washout. c. Twist off d. Tensile failure. e. Collapse. f. Burst. g. Down hole vibrations. h. Slip crushing. a) Fatigue failure z Mostly drill pipe failures are caused by fatigue. z Fatigue is the combined effect of tension, torsion and bending. z The cyclic reversal of stress that results in as the string is rotated. z Fatigue is accelerated when string is rotated in a section of directional & crooked hole. z Failure of the drill pipe due to fatigue takes place in the pipe body generally in the area where slip is set. z Fatigue fractures are progressive beginning as micro cracks that grow under the action of cyclic stress. z The rate of propagation is related to the applied cyclic load. Since the crack develops from the inside of the drill pipe and no plastic deformation occurs these cracks are very difficult to detect. z Fatigue results in washouts and twist off, in drill collars it takes place in the connection with the pin being left in the box. z Fatigue results in washouts and twist off. Fatigue also results in heat checking of tool joints. z Tool joints which are rotated under high lateral force against the wall of the hole may be damaged as a result of frictional heat checking. z The heat generated at the surface of the tool joint by the friction with the wall of the hole under high radial thrust may raise the temperature of the tool joint steel above its critical temperature. z The hardness of the affected surface is normally 3/16” below the OD. z The heat checking in the presence of mud causes alternate heating and quenching. z This results in numerous irregular heat check cracks often accompanied by longer axial cracks sometimes extending through the full section of the joint and wash outs may occur. z Surface imperfections caused by slip marks, cuts, tong marks, grooves caused by rubber protectors, welding and down hole notches caused by junk greatly affect the fatigue limit. b) Washout z A washout is a place where a small opening result in forcing the drilling fluid through pipe. z It is usually the result of a fatigue crack penetrating the wall of the pipe. z Wash out may also be caused by a damaged shoulder of box and/or a damaged pin. z Wearing out and tool joint gets worn out and connection not made up to its recommended torque. c) Twist off Usually caused by the fatigue crack extending around the pipe and causing the pipe to break. This type of failure usually occurs in the following manner : 162

Down Hole Complications z z z

z

Most failures occur when rotating or when picking the pipe off bottom immediately after drilling rather than pulling on stuck pipe. Most failures occur within 1m of the tool joint on either end of the pipe. Failure that originate from the outside of the pipe are usually associated with slip marks or other surface damages such as gouges, welding arc spots, marks made by drill pipe protectors, etc. Progressive growth is indicated in such damages. In case of stuck pipe, failure frequently occurs in a location where a fatigue crack has developed but has not progressed to the point of failure.

d) Tensile failure z The drill string can fail due to tension alone i.e. the total weight of the drill stem member together exceeds the pipe yield value. The design of the drill stem for static tensile load requires sufficient strength in the top most member of each size, weight, grade and class of drill pipe to support the buoyed weight of all hanging load below it. Rated tensile capacity is the product of the minimum yield strength and its cross sectional area. The actual tensile strength will be more because the yield strength is normally high than the minimum specified tensile strength. z The tensile failure will in most cases be located between the upsets. z Although this type of failure is usually near the top of the string, but variation in wall Fthickness and tensile strength between different pipes can cause pipe to fail somewhere lower in the string. z Tensile failure of the tool joint is rare because the tool joint has a greater cross sectional area than the pipe body. z The exception is when a slim undersized connection is used or the tensile capacity of a pin neck is weakened by higher make up torque. z In tensile failures the pipe body usually bottle necked near the fracture. z Tension factures surfaces often show extensive plastic deformation. Facture surfaces will be oriented 45 degrees to the axis of the pipe. Tensile failure usually occurs if z Error in the weight indicator. z While pulling accidentally or purposely more than the rated capacity. z The wrong size, weight or grade of string is in the hole due to improper design or due to mix up during tripping. z The pipe is of lower class than assumed because of improper inspection or excessive wear since last inspection. e) Collapse failure: Drill pipe may be subjected to an external pressure higher than the internal pressure. This condition usually occurs during drill stem testing and may result in collapse of the drill pipe. The collapse pressure is the maximum in the lower most drill pipe. The drill pipe will be mashed flat or into a half moon shape. f)

Burst failure: Also this type of failure is extremely rare but it can occur in any operation with a high differential pressure from inside the pipe, for example when well testing or fracturing.

g) Down hole vibrations z Although some down hole vibrations are inevitable, severe down hole vibration can cause drill string fatigue (washout / twist off), crooked drill string, premature bit failure and reduced penetration rates. 163

Drilling Operation Practices Manual z z z

i)

These vibrations cause three component of motion in the drill string and bit axially, torsional and lateral). All three dynamic motions may coexist and one motion may cause the other. There are number of mechanisms which can cause severe down hole vibrations. For mechanisms, their symptoms and methods of control are described below : Slap stick Non uniform bit rotation in which the bit slows or even stops rotating momentarily, causing the drill string to torque up and then spin free. z This mechanism sets up the primary torsional vibration in the string. Primary symptoms are surface torque fluctuations (greater than 15% of average), increased MWD shock counts, cutter impact damage, drill string washout/ twist off, connections over-torque or back-off. z This can be controlled by reducing WOB & increasing RPM, modify mud lubricity, reduce stabilizer torque (change blade design or no. of blades, use non rotating stabiliser or roller reamer), adjust stabiliser placement, smooth well profile and rotary feed back system. z

ii) Drill string whirl z The BHA (or drill pipe) gears around the hole. z The violent action slams the bit against the hole. z The mechanism can cause torsional and lateral vibrations. z Symptoms are: drill string washout/twist-offs, localized tool joint or stabiliser wear, increased average drilling and off-bottom torque. z To control this, lift bit off bottom and stop rotation, drill with reduced RPM. z Avoid drill collar weight in excess of 1.15 to 1.25 times WOB, use packed hole assembly, reduce stabiliser torque, adjust stabiliser placement, modify mud properties, consider drilling with down hole motor. iii) Bit whirl z Eccentric rotation of a bit about a point other than its geometric centre. z This causes high frequency lateral vibrations of the bit and drill string. Symptoms are: cutter damage, uneven bit gauge wear, over-gauge hole & reduced ROP. z To control this, lift bit off bottom and stop rotation, then reduce RPM & increase WOB, consider changing bit (flatter profile, anti whirl), use slower RPM when tagging bottom and during reaming, pick off bottom before stopping rotary use stabilised BHA with full gauge near-bit stabiliser or reamer. iv) Bit bounce z Large WOB fluctuations causing the bit to repeatedly lift off & impact the formation. z This mechanism often occurs while drilling with roller cone bits in hard formation. Symptoms are large axial vibrations (shaking of hoisting equipment) large WOB fluctuations, cutter and/or bearing impact damage, fatigue cracks and reduced ROP. z To control this run shock subs, adjust WOB/RPM, consider changing bit style, change length of BHA. h) Slip crushing: A majority of the drill pipe failures occur in the slip area. These type of failures are caused by: 164

Down Hole Complications z z

Highly concentrated stresses originating from axial and transverse loads that are not equally distributed over the full gripping surface of the slip. Improper handling methods which result in abnormal markings and stressing in the slip area.

Drill pipe failure in the slip area can be prevented by z Maintaining rotary master bushing and slips to correct API specifications and by good handling techniques. Do not use new master bushing in a worn rotary table and vice- versa. When wear or non uniform gripping of the slip dies is observed, the entire set of dies on the slip must be changed. Never use re-sharpened dies. z Maximum axial and transverse loads do not act at the same section in the slip area. The critical section occurs at the zone of maximum crushing pressure, and at this point the axial load is less than the hook load. The calculated axial load verses the transverse load factor must always be considered when designing a drill string with excessive hook loads. The presence of transverse load diminishes the total load in pure tension which causes yielding. z Do not overlook the effect of transverse load. The transverse load acts as a compressive force on drill pipe and, with adverse conditions of equipment or handling techniques, bottlenecking or crushing will occur when excessive hook load is prevails. This condition exists because the collapse strength of the drill pipe in the slip area is exceeded. z Use thick wall tube drill pipe. Proper handling techniques z Do not stop the downward movement of the drill string with the slips instead of the brake. This result in the area immediately below the last gripping surface of the rotary slip to an increased tensile load, which if the weight is sufficient will elongate the drill pipe in this area. This elongation yields the pipe and renders it useless. z If the slips are caught in the tool joint area, there is a possibility of damage to the slip. Inspect the slip immediately when this happens and carry out repairs if necessary. z Do not let the slips ride the pipe. z Always use slip of correct specifications of tubulars. z Always use back up tong when breaking or making connection. z Never allow the pipe to rotate in slip. 13.4 BIT FAILURE Fishing of bits especially roller bit cones is one of the most common fishing operations. Recovery of bit cones in soft formation This depends on the size & number of bit cones left in the well. The following is a generalized procedure for recovery of lost bit cones. z If only one cone is lost in the well, a hard formation mill tooth bit run with a junk sub will break up the cone. Part of the junk will be walled off and the remaining will be collected in the junk sub. Usually the junk walled off will not fall back in the hole. z Run a reverse circulation junk basket if two or more rollers are left in the hole. z Magnets are less effective in recovery of cones in loose formation as the cones are covered by cuttings and stuck in the bottom of the hole. However if a recessed magnet with circulating ports dressed with a mill type shoe is available, it can be rotated with circulation to release the cones allowing the magnet to catch them. 165


Recovery of bit cones in medium hard formation Since there is a possibility of the bit getting under gauged prior to its failure it is advisable to make a bit trip to prove the hole to bottom, especially prior to running a junk basket. There have been cases of the junk basket getting mechanically stuck against a cone which is partially embedded in the wall of the well bore. z Recovery of lost bit cones is more commonly done with junk basket. A junk basket run with a milling shoe will invariably be able to cut a core of sufficient length to accommodate the lost cones and other minor junk. z A flat mill will break up the junk although it will not be as effective as a ribbed cutting face mill or concave mill in breaking up and walling off the junk. Run a junk sub along with the mill. A clean out trip with a hard formation bit with junk sub may be required after milling. z Unless a magnet can be run on wireline, it may not be economical to run it on drill pipe. Magnet being a contact tool, any accumulation of cuttings on the junk will not permit recovery of cone/s. When run on drill string, magnet must be dressed with a mill type shoe and have circulation ports to permit rotation with circulation to remove cuttings from the top of the cone/s. Recovery of bit cones in hard formation z Since there is a possibility of the bit getting under gauge prior to its failure it is advisable to make a bit trip to prove the hole to bottom, especially prior to running a junk basket. There have been cases of the junk basket getting mechanically stuck against a cone which is partially embedded in the wall of the well bore. z The most effective way to remove bit cones is to mill them with a concave mill run along with a junk sub. A clean out trip with a hard formation mill tooth bit and junk sub will clear the bottom of the hole. Run this bit only for a short time to prevent leaving teeth, and possibly more cones. z Junk baskets are less effective in hard formation. Longer time taken to cut the core can damage the fingers of the junk basket. The mill shoe often gets worn out before a core can be cut of sufficient length to hold the junk in the basket. z A magnet may be more effective if the formation against which the cones are lying is trap or basement. If the magnet can be run on wireline (sandline) time taken for tripping with drill pipe can be saved. Parted bits and large junk z Bits and other large pieces of junk are almost always removed or walled off by milling. A number of trips with a mill may be required to clear the junk. z A junk sub should always be run with the mill. z If the junk is small enough to enter a junk sub, then run a junk basket. z If the top of bit is a clean pin then run a matching box and screw into the pin of the bit. z If the bit has turned over especially in large diameter holes, make a trip with a impression block. z A taper tap may be used to catch the bit which is lying with pin up. z The most common method of removing a bit which cannot be removed by a matching pin or a tap is to mill it into small pieces.

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13.5 CASING FAILURE AND REPAIR Failure of casing is an area of increasing concern. The extent of casing failure covers wells offshore and onshore varying in size from 13 3/8” to 5 ½”. Failure of casing occurs mainly due to: z Leakage from joints due to improper make up. z Wear out of intermediate casing due to tool joint of drill string /junk inside casing. z Collapse & burst casing. z Improper design. 13.5.1 Leaks Casing leaks are the most common failures and often occur in association with most other failures. The major causes for leaks are: z Improper make up during running. z Drill pipe wear during drilling. z Wear due to running stabilizers in cased hole. z Mechanical wear during fishing and specially milling. z Corrosion and to a lesser extent erosion and mechanical wear during production life of the well. 13.5.2 Casing Split or Burst Split or burst casing occurs from many causes. z Bumping the plug too hard during cementing. z Applying excess internal pressure sometimes in combination with high tensile loading. Excess internal pressure may occur while testing liner top or testing casing before drill out. z Some failures that cause casing leaks may also cause split or burst casing. z Casing may split while hanging long, heavy liners. z General causes include inadequate strength due to improper design, or worn casing at the point where liner setting tool slips engage the casing. z Casings can also split due to high density perforation specially in the higher strength steels. z Casing may also split due to structural defects. 13.5.3 Parted Casing These types of failures are caused mainly due to: z Improper design. z Operations or mechanical failures due to improper construction. Parted casing usually occurs at the connections especially in lesser strong connections. z Split or burst casing may also part due loss of structural integrity. z Casing may part during running due to improper handling, such as being lowered rapidly lowered and stopped abruptly, especially with long, heavy casing strings. z Other causes can include excess wear and resulting loss of tensile strength, pulling hard while working stuck casing and bumping the plug too hard during cementation. 13.5.4 Collapsed Casing Casing collapse due to various reasons some of which are the same which cause casing leaks. Some of them are: z Improper design. z Failure to fill the casing during running. 167

Drilling Operation Practices Manual z z z z z

Wear reduces body strength so the external pressure may cause the casing to collapse. Anything that reduces wall thickness, including wear or corrosion increases susceptibility to collapse. Casing may collapse due to squeezing or treating below a packer set in the casing. Worn or poorly designed production casing may collapse when the hydrostatic head is reduced by compressor / nitrogen application. Some times casing collapse may be due to shifting or flowing formations like massive salt sections.

13.5.5 Factors Affecting Casing Repairs z Casing type, size & depth of failures. z Whether the problem is in cemented or un cemented section. z Whether the option of using extra string of casing is available. z Formation type, pressure, fluid in the formation & transition zone. z Age of the well. z Current status of the well (drilling or production). z Productivity from the well. z Severity of failure. Casing repairs are best reviewed & evaluated by considering the following z

How does the failure affect future & current operations? The first thing that needs to be evaluated is whether the failure needs to be repaired. The failure may not have an adverse effect on operations; if not, and no other hazardous conditions exist; do not repair the casing.

z

Is the internal diameter restricted? An immediate repair may be needed if the restriction is preventing the running of full gauge tools / completion string and other operations. There are some exceptions like a partially collapsed larger diameter casing above a drilling liner which is not impeding the normal operations. A partially collapsed casing above a conventional completion like an intact packer and tubing with no annulus pressure build up may not be repaired.

z

Can the failure be repaired by normal future operations? A casing failure may not pose a problem in current operation and can be effectively repaired or effectively eliminated by future operations. For example a drill pipe can cause a hole in deep surface or intermediate casing. If this does not create an immediate drilling hazard, drilling operations can continue without making a repair. The hole can be covered later by a production casing or liner that extends over the hole.

z

Can the failure be patched off or packed off the leak? Some casing repairs can be made by a simple casing patch or packing off the leak.

z

Can the casing be plugged off and repaired later? This applies mainly to production casing. If the casing fails in the lower section, one procedure would be to set a plug and isolate the failure. Production testing of the upper objects can be done. If the well is deepened later, repaire the failure.

z

Can an extra casing be run? It may be possible to repair the casing by running another string of casing, a liner, or a stub liner. 168


13.5.6 Casing Repair Methods Type of failure must be acknowledged. The objective or status of the well is also to be considered. In general make the simplest repair possible that will accomplish the desired results. Consider plugging back and sidetracking, plugging back and drilling another well, or plugging back and abandoning the hole. z Loose casing shoe joints: These are generally repaired by cementing the joints to fix them in lace and prevent movement. Then run a full gauge mill and ream as necessary to ensure full gauge hole. In a few cases if the casing has been set at bottom in a gauged hole, it may not be necessary to cement the loose joint and operation can continue. z Squeeze and clean out: Generally this is the simplest method of repairing a casing failure such as a leak. Squeeze the section and run a full gauge tool through to ensure that the hole is full gauge. The disadvantage of this method is that it leaves a potentially weak section that must be considered during future operations. Squeezing of cement can be done through open end tubing or drill pipe, retrievable packer or cement retainer. z Pack off the failure: Pack off the failure by isolating it. A damaged section can be isolated from the remaining well bore by running a packer on tubing or small size casing. Alternately run two packers on tubing or small size casing separated by the length of damaged casing. Disadvantage of this method is that it reduces the working inside diameter of hole and usually restricts operations below the failure. Nevertheless, it is the fastest and most economical type repair. z Patch off the failure: Various types of inside casing patches are available. Generally they include a ribbed or corrugated, thin- wall steel cylinder. Run it into the cased hole and position it over the failure (usually a hole). Expand the sleeve by pulling the mandrel through it to form a sheet of metal inside the casing. Inside patch reduces the inside diameter of the casing by a small amount, which can cause burst and collapse strength to reduce. z Repair parted casing in place: One of the best methods where possible is to establish circulation through the failed section and perform a primary cement job under a retrievable packer or cement retainer. Alternately, perforate below the failed section and perform a primary cement job in a similar manner. In case of a retrievable packer or open end tubing or drill pipe, take precautions to ensure that this assembly does not get stuck in cement. Pull the cementing assembly above the damaged section of casing and reverse out so that all excess cement is circulated out. Pressurize the casing to ensure that the cement does flow back into the well. Another method is to squeeze the section till it holds the desired pressure. Clean out with bit. z Pull, repair, rerun and reconnect parted casing: This is one of the best casing repairs, but it is not applicable in many cases. Back off or cut the casing below the ailed section and pull it. Replace the damaged section and either screw back into the lower section or connect it with an external casing patch. The external casing patch can be a lead seal or lead seal cementing type. z Run another string of casing or stub casing or tie-back liner: If the casing is large enough run another casing or stub casing or liner. If a failure is in the bottom of intermediate casing, it should be covered by production casing. Repair a failure at the bottom of the hole above a liner with a tie-back liner. If the failure creates an immediate hazard, it may be squeezed off and covered by casing or a liner. z Failure in casing not cemented: When possible, pull the casing, replace it run and reconnect in a way similar to parted casing. Otherwise try to cement the casing in place with a primary

169


z

cement job. Running another string of smaller diameter casing or tie back or stub liner may be applicable. Failure in cemented casing: This is one of the more difficult casing repair job. Generally the cemented casing cannot be repaired by replacing the casing above the failure. Pulling the uncemented pipe and milling the remaining casing till the bottom of the damaged casing is removed may not be an economically viable alternative. If the failure is such it restricts the inside diameter of the casing then the diameter should be restored by rolling out or swaging or milling out and squeezing if necessary. Running another string of casing or liner may be a viable alternative.

13.5.7 Summarised Casing Repair Flow Chart

COLLAPSED

PARTED

LEAK, SPLIT OR BURST

REPAIR CASING IN PLACE MILL OR REAM OUT SET INTERNAL CASING PATCH

CUT, MILL AND FISH OUT THROUGH THE PARTED SECTION. WASH OVER CASING

B A C K O F F

PACK OFF DAMAGED SECTION

SWAGE OR ROLL OUT

MILL TOP CLEAN

RUN CASING WITH EXTERNAL PATCH

BACK OFF LEAVE THREA D UP

RUN CASING WITH ALLIGNMENT TOOL AND MAKE UP

SQUEEZE, CLEAN OUT TEST LAND CASING NIPPLE

RESUME OPERATIONS

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13.6 DETERMINATION OF THE LENGTH OF FREE PIPE IN A STUCK STRING Find out the length of free pipe by the following equations, L

=

2.1 x 103 x A x e ———————— P2 - P1

Where : L = Length of free pipe (m) A = Cross sectional area of drill-pipe (cm2) e = Differential stretch (m) P2 - P1 = Differential pull (T) Considering a correction factor of 1.05 for tool joint the equivalent length (Leq) of free drill pipe is given by: Leq = 1.05 x L Note: This method is fairly accurate in straight wells. 13.6.1 Method of Application of this Technique Prior to measuring the differential stretch the string should be thoroughly worked so as to minimize the effect of residual stress in the string. A pull (P1) of 10-15T greater than the air weight of the drill string is applied to the stuck string and a mark is made on the kelly or pipe as the case my be. This pull is released and equal pull (P1) is applied once again. Another mark is made on the kelly. The two marks do not coincide due to the friction in the hole. The mid point between the two marks is taken as the upper reference mark A. A pull P2 (P1+ 10-15T) is applied and a lower reference mark B is made following the steps mentioned above. The distance between the two marks A and B is measured as ‘e’. Note : The pull must be within the safe limits of the margin of over-pull of the string. Example String stuck at 4200m in 8-1/2" hole with mud density 1.4. Drilling String: 1500m of 5", 19.5 ppf# (NC50) E grade class 2 drill pipe weight per meter 31.02 Kg/m. 1500m of 5", 19.5 ppf# (NC50) G grade class 2 drill pipe weight per meter 32.63 Kg/m. 1000m of 5", 19.5 ppf# (NC50) S grade class 2 drill pipe weight per meter 33.64 Kg/m. 200m of 6-1/2" x 2-13/16" drill collars weight per meter 136.4 Kg/m. Step I : Calculate the margin of over pull (MOP). Weight of the drill collars in air = 200 x 136.4 Weight of E grade drill pipe in air = 1500 x 31.02 Weight of G grade drill pipe in air = 1500 x 32.63 Weight of S grade drill pipe in air = 1000 x 33.64 Buoyancy factor in mud of 1.4 SG is 1 - 1.4 x 8.33 65.5 171

= = = = =

27.280T 46.53T 48.945T 33.64T 0.822


MOP of the drill string is given by Tensile strength of the pipe x factor of safety (0.9) minus the buoyant weight of the string. MOP of E grade drill pipe (class 2) with tensile strength (122.67T) is: 122.67T x 0.9 - 0.822 x (27.280 + 46.53) = 49.73T MOP of G grade drill pipe (class 2) with tensile strength (171.73T) is: 171.73 x 0.9 - 0.822 x (27.280 + 46.53 + 48.945) = 53.65T MOP of S grade drill pipe (class 2) with tensile strength (220.8T) is: 220.8 x 0.9 - 0.822 x (27.280 + 46.53 + 48.945 + 33.64) = 70.16T Hence the MOP of the string is the minimum of the three i.e. = 49.73T Buoyant wt. of drill string is: 0.822 x (27.280 + 46.53 + 48.945 + 33.64) = 128.56T. 128.56 Air of wt. of the string = ———— = 156.4T 0.822 Hence while working on pipe or during calculation of the free point the hook load of the string should not exceed 128.56 + 49.73 = 178.3T Step II: Apply a pull (P1) of 160T and make a mark of the string. Release the string weight to 128T and again pull to 160T. Make another mark of the string. Mid point between the two marks is point A. Apply a pull (P2) of 175T and make a mark on the string. Release the weight to 128 T and again pull to 175T. Mid point between these marks is point B. The distance between A and B is the stretch for a differential pull of (P2-P1) i.e. 175-160 = 15T. Let us assume this distance is 62.8 cm i.e. 0.628m Step III: 2 Apply the formulae with A = 34.03 cm , e = 0.8m, P2-P1 = 15T 2.1 x 1.05 x 103 x 34.03 x 0.8 Length of free pipe = —————————————— = 4001.93m 15 Back Off of a stuck pipe 1. Before back off first determine the free length of drill string by either the differential stretch method or more accurately by electro-logging technique. 2. Make up the string to the maximum of 80% of the torsional limit. 3. Put the neutral point on a level with the joint to be backed off. The weight indicator tension is given by: PxA T = W + ———— 1000 where T = Weight indicator tension in tons. W = Buoyant weight of free drill string plus weight of kelly, traveling block, hook, etc. (tons) P = Hydrostatic pressure at the point of back off (kg/cm2) A = Area of the mating surface of the tool joint, cm2 172


4. Work 80% of left hand torsion of that applied in step 2 to the point of back off. 5. Run in the string shot to point of back off desired and detonate the string shot. 6. If the string is not fully opened, count the number of turns released. If it is less than that applied in point 4, then the joint is partially opened and by working the torque down the joint may get fully opened. Note: If back off is done without the kelly connected, then in this case the weight of kelly & swivel etc. is not be considered. 13.6.2 Back-off Procedure in Highly Deviated (ERD) Wells When backing off in a deviated hole it is difficult to calculate the loss of weight due to buoyancy, friction in the hole & weight of pipes lying on the low side of the hole. Example Assume that following drill string is in the hole : 1500m x 31.24 Kg/m drill pipe 192m x 75 Kg/m HWDP 118m x 219 Kg/m of 8” D/C, stab, reamers 118m x 219 Kg/m of 8” D/C, stab, reamers

= = = =

46.86 T 14.4 T 25.842 T 25.842 T

TOTAL WEIGHT IN AIR = 87.102 T In this case assume that the weight indicator reading before pipe got stuck was 50 T. (this should be recorded in the driller’s daily log book.) The wt. of pipe in the hole would be = 50T Minus the wt. of block = 11 T TOTAL WT. IN THE HOLE Wt. in air Wt. in the hole

= = =

39 T 87.102 T 39 T

LOSS OF WT. = 48.102 T Loss of wt. due to buoyancy, friction & pipe lying on the low side of the hole is 48.102 Kg. or 52.22 % . To back off at the top of the D/C. we have 1500m x 31.24 Kg/m drill pipe = 46.86 T 192m x 75 Kg/m HWDP = 14.4 T Total Wt. in air = 61.26 T Minus 52.22% buoyancy & friction etc. = 31.99 T Total wt. in the hole = 29.27 T Plus wt. of the block = 11 T Plus 5000 Kg. pull = 5T WEIGHT TO BACK OFF FROM TOP OF 8” D/C = 45.27 T Note : Another method that could be used, starting the calculation with wt. of what is left behind in the hole. In that case use rotational weight. 13.6.3 Precautions While Backing Off with String Shots (Deviated Holes) z When taking the free point with a logging unit, the tool pusher and logger should be in the logging cabin with the logging engineer to study the behavior of the tensionand torque indicators and to get an idea of the string reaction to the pull and torque required to overcome friction. 173


Always record the tension reading first, prior to taking torque readings. Especially in deviated holes, residual torque can give false indications of the pipe being free when applying tension. z After every torque reading, rotate the string a few turns to the left to get rid of any residual torque. z Check any reading taken on the indicators with the logging unit monograph to see if the meter point readings confirm. After the free point is determined, the left hand torque has to be worked down the hole before the string shot. z · Sometimes in deviated holes it is necessary to use the kelly to work down the torque, even if it is required to back off high up the hole first to be able to install the kelly. z

Note : If a fish is left in the hole after a back-off, then the actual weight of the fishing string is known. When this fishing string has been latched onto the fish, then the total string weight to the next lower back off point can be calculated as : The neutral weight of the fishing string PLUS the weight of the stuck string down to the new back off point MINUS the percentage buoyancy and friction loss previously calculated for the original string. Counter check this figure again with the remainder of the fish in the hole and the neutral point of the string when it was still free. When running back in the hole with a fishing string, recheck all connections and make them up to maximum tightness. Remove the rubber protectors because they can account for approximately 10% of the total friction. Transmitting Torque Down the Hole The following information is required 1. What is the equivalent in amperes or ft-lbs or m-kgs of the drill string make up torque? This value should not be exceeded when applying left hand torque, and preferably 60 - 80% of this value should be used. 2. What is the string weight while rotating? This is considered the neutral weight. Do not confuse this weight with the free weight of the string, which is the weight of the string above the stuck point. 3. What is the weight going down? 4. What is the weight pulling up? For an estimate, assume that the rotating weight is slightly less than 50% of the difference between weights pulling up and going down, added to the weight going down. 5. What is the free weight of the string to the back-off point? For accurate determination, see the calculation in example above. Procedures 1. Run in the string shot to 500 m below the sea bed/wellhead As an example, assume that: Rotating weight (neutral) = 95T Weight going up = 135T Weight going down = 70T Free weight (to back off pt.) = 80T Loss weight due to buoyancy and friction = 31% (calculated same way as in example) Make up torque equivalent = 200 Amperes

174


From the observations during the free point indicator runs, it was observed that there was a lot of friction in the hole (see the weights going up and going down). Assume that with 1 rubber protector per 2 singles, 10% of the friction is caused by the protectors. 2. The torque must be worked down the hole, turn by turn, as follows a) Pick up the string to the weight going up, then lower down to the neutral weight. b) Apply 1 turn of torque (observe Ampere meter) and lock the rotary table (assume kelly is used). c) Reciprocate the string between weights going up and going down, say 20-25 times e.g. between 120T and 75T. d) Lower the string to the neutral weight (do not pick it up to the neutral weight), and apply another turn of torque. Reciprocate the pipe again as outlined above. e) Continue in the same manner until 50% of the required number of turns has been worked down (e.g. 1 turn per 1000 ft for 5" drill pipe). f) When applying the next turn of torque, check the ampere meter. If after the initial reading the ampere meter remains around 200 Amps or higher do not apply the additional turns but continue to work down the previous turn again until the Ampere meter only indicates a slight increase over the previous reading, because only then the torque has been worked properly down the hole. 3. When 50% of the total required reverse torque has been applied, work the string only down to the free weight (80T) and not lower, to prevent backing off at a random depth. 4. Once all the required turns are worked down, pick up the string to the free weight PLUS the % buoyancy, then lower down to the free weight. This is most important because coming to the free weight on the upward stroke means that the pipe is most likely still in compression at the back off point and will not back off. A tension of 5T – 10T at the back point is desirable for a successful back off. 13.7 GENERAL GUIDELINES ON FISHING 1. If failed to stab in fish with matching pin in right hand rotation after tagging, try to stab in by giving one or two turn left hand rotation after tagging the fish. 2. FAvoid using welded guide in the fishing assembly. Always use threaded connection guide for centering of the fish. 3. While engaging fish with matching pin, the jar / bumper sub pin should be protected by using an end connector. 4. Always use strongest catch tool available for the particular size of the fish. 5. If washout hole is suspected, always use oversize guide or wall hook guide with overshot in the first run itself. 6. While using overshot with deflection tool like knuckle joint/bend sub, the lip of the overshot should be in line of the direction of deflection. 7. Standard fishing assembly should consist of : a) Overshot or any other catching tool. b) Bumper sub (min 18" stroke). c) Hydraulic up jar. d) 3-4 singles of drill collars. 8. While jarring apply required pull to activate the jar. 175


9. In crooked hole for maximum effective jarring, use jar accelerator along with the jar. 10. Jar accelerator should be placed above the drill collar which is put above the jar for better impact. 11. Drill collar size above jar must not be more than O.D of jar. 12. Before lowering jar make sure that I.D. of jar is sufficient to pass string shot or free point indicator tool. Record all the dimensions of all fishing tools lowered in the well. 13. Try to avoid using Rotary male tap as string shot tool cannot be lowered through it. 14. Prior to starting fishing operation or engaging the fish always circulate thoroughly. 15. In case of suspected mud cut or string failure, pull out the string using pipe spinner or manila rope, never rotate the rotary to avoid dropping of string. 16. In case of mechanical back off or string failure always count the number of stands and singles pulled out. 17. While backing off keep the neutral point at the back off point. In directional wells or when in doubt it is better to have the shot in tension. 8. After string shot, before picking up the string ensure that all the torque is consumed or neutralized. 19. After backing off, tag the fish top prior to pulling out so as to have an idea of the hole size at the fish top. 20. Dress the over shot with the same size of grapple as the O.D. of the fish. When reduction of tool joint is around 1/8”, use grapple size 1/8" less than anticipated O.D. of fish. 21. If key seat is suspected in the hole, dress the over shot with over size guide or wall hook guide. 22. After engaging fish with catching tool, reciprocate with gradually increasing tension before trying to lift. 23. Before lowering junk basket, ensure that the catcher rotates freely. 24. In RCJB operation, before dropping the ball ensure that the hole bottom is flushed. 25. Select the proper shoe for RCJB prior to assemble the tool. If the junk is large & lying loose at the bottom, use finger shoe. If the formation is relatively soft and the junk is lying loose, use type “A” mill shoe. For hard formation and if fish is lying embedded, use type “B” or type “C”, ITCOLOY faced mill shoe. 26. A casing Spear may be equipped with a mill type nut in place of the standard bull nose, if the top of the fish is distorted. 27. A sub type nut may be installed in place of the bull nose nut should it be necessary to run a packer below casing spear for establishing circulation through fish. 28. Cutting casing against joint must be avoided. 29. For smooth cutting by internal mechanical cutter use bumper sub above predetermined weight of drill collar. 30. In case of bit cone loss in medium hard / hard formation, use junk mill and junk sub to clear junk. Use of RCJB may lead to breaking of junk retaining fingers of the catcher. 31. Make a bit and junk sub trip prior to run in diamond bit. 32. While fishing wire line inside casing, stop plate should be used above wire line spear to avoid wire line coming above the spear and getting stuck inside casing. The clearance between the stop plate and I.D of casing should be half the diameter of wire line. 33. Be aware of the limitations of the fishing tools. 34. Use positive catching tools as far as possible. Non positive are to be used only when positive catching tools cannot be used. 176

Casing Operations

CHAPTER - 14

CASING OPERATIONS PREPARATIONS PRIOR TO LOWERING OF CASING PIPES AND TUBING It is essential to inspect the damage / defect incurred during transportation and storage of casing pipes and tubing at site prior to lowering in the well. Additionally, inspection of handling tools, preparation of pipe tally etc. are also necessary before lowering of casing pipes. 14.1 GENERAL PRECAUTIONS i. The casing policy should be available at well site stipulating the design of the casing string. It should include the location of Float shoe & collar, short pipes, the various grades of steel, weight of casing & type of the connection etc. ii. Short casing pipes may be used as per loggers’ requirement for faster calibration of well depth. iii. It should be ensured to lower the pipes in exactly the same order, as given in casing policy of well. In case the specification of any pipe is not identified, it should be laid aside until it is identified. iv. In case of lowering of mixed string, of different grade, weight etc., ensure that appropriate casing is accessible on pipe rack as per the program. v. There should be at least one joint in between Float Collar and Float Shoe for shallow wells. For moderate depth wells, two joint spacing and for deep wells three joint spacing may be kept to avoid cement contamination around shoe. vi. In deep / critical wells, hydraulic testing of casing pipes should be carried at DTYS before dispatching for lowering. vii. Proper handling equipment should be used to prevent damage to the casing by slip and tong marks. For deep / critical wells, full engage casing spinning / tightening tong should be used. viii. It should be ensured that connectors / pup joints do have the adequate thread capacity to support the load and are compatible to the size & type of casing / tubing. ix. The settling of pipes on bottom of the well or otherwise in compression stage should be avoided to prevent buckling of pipe. x. In case of conventional Float collar / Shoe, the casing should be periodically filled with mud while being run keeping a check on the weight of the casing string. Generally filling after every 5 – 6 joints should be adequate. In deep wells, running the casing empty might collapse the casing especially when heavy mud is in the annulus. Filling should be done with drilling mud weight, using a conveniently located hose of adequate size with quick opening and closing plug valve in another mud hose. xi. Make wiper trips with the existing BHA especially through tight spot sections. xii. Pipe sticking tendency / drag to be noted down in the last bit trip and remedial measures taken accordingly. xiii. Mud to be thoroughly conditioned for achieving proper parameters to avoid complications during casing running. xiv. Stabbing board to be set up in advance properly especially when spider elevator is used for casing running. 177


xv. Casing pipe should be handled with utmost care during transportation, stacking and running in so as to avoid shock loading that might arise due to Rolling casings from trailers over a sharp wedge; Bumping casing against stacked pipes; Improper handling tools; Setting slips against moving pipes; etc. Note : The foregoing mud fill up practice is not required if automatic fill up float shoes andcollars are used. However, air blow technique should be employed to ensure actual mud fill up indication. 14.1.1 Preparations of Casing / Tubing Tally i. A steel tape calibrated in centimeter should be used. ii. The measurement of pipes should be made from the outermost face of the coupling to the pin end, where coupling or the box stops when the joint is made up power tight as explained below: • On round thread joints, this position is to the thread vanish point on the pipe; • On buttress thread pipe, this position is to the base of the triangle stamp on the pipe; • On extreme line casing, this position is to the shoulder on the externally threaded end. iii. The measured length of each pipe should be written on the pipe with paint preferably near the coupling end. iv. Prepare the pipe tally. 14.1.2 Inspection of Handling Tools Handling tools of appropriate size and capacity should be selected. Inspection of all handling equipment is necessary before starting the lowering of pipes. Make shift arrangement is not desirable. Inspection of all handling tools viz. Manual & Hydraulic Tongs, Hand slip, single Joint Elevators, Side door elevators, Heavy duty elevators, Spiders, Pup joints, Instrumentation at Driller’s console including Weight indicators & torque gauge etc., shall be carried out prior to taking up lowering of casing pipe and tubing. For more detail OISD Std. 190 should be referred. 14.1.3 Threads Preparation The following precautions should be taken regarding preparation of casing pipe threads prior to make up: i. Clean and inspect the threads. ii. The pipes with damaged threads should not be used. iii. Each coupling should be checked for make up before taking up the pipe to derrick. If the standoff is more, check the coupling for tightness. iv. Thread compound should be applied to the entire internal and external threaded areas as recommended in API 5A2 or equivalent prior to stabbing. v. Quick release coupling should be used while taking pipes from rack to derrick in order to avoid damage to threads of pin end. vi. In case thread protector are used for taking up pipes from pipe rack to derrick, clean thread protector properly tightened on the pin end of the pipe should be used. Adequate number of thread protectors duly cleaned should be available.

178

Casing Operations

vii. In case of XL threads, polished metal to metal sealing area of both the pin and box ends should be checked properly. If found defective, the pipe should be rejected. 14.1.4 Drifting Each casing pipe should be drifted for its entire length before lowering in the well, with cylindrical mandrels conforming to specification given in Annexure 3. Casing that does not pass the drift test should be rejected with proper marking. 14.1.5 Straightness Check at Dtys i.

All pipes should be visually examined for straightness. Pipe sizes 4.1/2” and larger O.D. should be checked for straightness by using a straight edge or taut string (wire). Deviation from straight, or chord height, should not exceed either of the following;

i.

0.2 percent of the total length of the pipe measured from one end of the pipe to the other end.

ii.

0.125 inch in the 5-foot length at each end.

Measurement of the deviation should not be made in the plane of the upset and coupling area. 14.1.6 Field Welding of Attachments on Casing Pipes Following precautions should be taken before taking up the welding job on casing pipes. i. Field welding may have adverse effects on various types of steels used in all grades of casing pipes and tubing unless due precautions are taken. ii. Welding on high strength steel should be avoided, as the heat from welding may affect the mechanical properties of high strength steel. iii. Welding is not recommended on critical portions of the string where tension, burst or collapse strength properties are important. iv. Welding of Float Shoe / collar with joint shall be done only with extreme caution. v. Prior to taking up the welding job, the authorized person should ascertain the welder’s qualification. vi. Preheating of 3” on each side of weld locations should be done to a temperature of 205 to 315 degree Celsius. Preheat temperature should be maintained during welding. Welded joint should be lowered after normal cooling only. 14.2 LOWERING CASING PIPES The following practice should be adopted for making up of casing pipes: 14.2.1 General Precautions i. Wobbling during make up lead to galling of threads. In case wobbling is observed while making up the pipes, it could be due to non alignment of thread with the axis of the pipes. To stop wobbling, the speed of rotation should be decreased. If it still persists despite reduced rotational speed, the casing should be rejected. ii. While making up the pin end, it is possible that coupling may rotate on the box end slightly. This does not indicate that the coupling on the box end is too loose but simply that the pin end has reached the tightness with which the coupling was screwed on at the manufacturer’s facility. 179


iii. In order to avoid shock loads during lowering of casing string, it should be picked up and lowered carefully with proper care while setting slips. iv. For premium casing pipes, recommended guidelines of the manufactures should be followed. 14.2.2 Making up Casing Pipes • While lowering first few joinst of casing, ensure that casing is made up to the base of the triangles marked on pin end and note down torque readings on the gauge. • Subsequently the average of these torque value will be reference for further tightening of casing joints. • For Round threads, casing should be made hand tight to the possible limit. For the proper number of turns beyond hand tight position the following is recommended; A) When conventional tongs are used for casing make up, tighten with tongs to proper degree of tightness. B) The joint should be made-up beyond the hand tight position at least three turns for sizes 4.1/2” through 7” and at least three and one half turns for sizes 7.5/8” and larger, except 9.5/8”and 10.3/4” grade P-110 and size 20” grade J-55 and K-55, which should be made up about four turns beyond hand tight position. C) In case of BTC threads, first 5 to 10 joints should be tightened to the base of the triangular mark and torque noted. Remaining joints may be tightened to the average torque with occasional checks for the triangular mark. • The manual tong should be provided with a reliable torque gauge of known accuracy. In case any irregularities are observed during initial stage of make up, pipes should not be tightened as these may be indicative of crossed threads, dirty or damaged threads, or other unfavorable conditions. 14.2.3 Casing Running In i.

Casing should be run at a controlled optimum speed to reduce pressure surges that could lead to lost circulation, caving etc. Generally Running in speed of 45 seconds to 2 minutes per single is practiced.

ii.

Special attention is to be given while passing through tight spot sections as found in the last caliper log.

iii. The connection / stationary time should be kept the bare minimum to avoid stuck up. In case of emergency shutdown, lower the single slowly and stopping briefly in between 2 to 3 feet interval. iv. Avoid casing fill up when inside open hole as stagnant time might lead to stuck pipe. The casing should be filled up completely within the previous casing shoe. v.

Avoid dropping foreign materials such as Hand gloves etc during casing fill up as it might clog the floating equipment.

vi. Unless warranted, the casing should be circulated after reaching TD. Preferable, casing should be tagged bottom with circulation having circulating head connected above. vii. Do not circulate with the shoe in open hole as cuttings could accumulate around shoe to form a bridge ceasing circulation. If mud condition / breaking gellation are required, then the same should be done within the previous casing shoe. 180

Casing Operations

14.3 CASING LANDING PRACTICES Selection of proper casing landing procedure is important to avoid excessive stresses and unsafe tensile stresses at any time during the life of well. In arriving at the proper tension and landing procedure, consideration should be given to factors viz. well temperature, pressure, temperature developed due to cement hydration, mud temperature & change in temperature during production operations. Any of the following casing landing methods should be adopted a) After the cement has set, casing should be landed with exactly under same tension that was present when cement displacement was completed in the wells in which mud specific gravity does not exceed 1.5 gm/cc (12.5 ppg). Also ensure during design of casing that standard safety factors were considered and outer most casing have sufficient strength to withstand the landing loads. b) Casing should be landed in such a manner that the casing at the top of cement is either in tension or completely balanced so far as tensile and compressive stresses are concerned. c) Where excessive specific gravity of mud is used, casing should be landed with top of freeze point in tension. d) The approach suitable to well requirement to keep required tension or compression at the freeze point should be adopted. In practice, it may not be possible to anticipate all the changes of physical conditions that may occur during life of well. Landing casing in “as cemented” condition would be a reasonable approach. 14.4 PRECAUTIONS FOR CORROSIVE ENVIRONMENT Casing pipes can be damaged by internal and external corrosion. The condition of the casing can be determined by visual or optical instrument inspection. Casing caliper survey should be carried out to determine the condition of the inside surfaces which indicate the location and severity of corrosion. The following methods and measures should be used to control corrosion of casing: a) In case of external corrosion and stray electrical current surveys indicate that relatively high currents are entering the well, the following practices are recommended: • Good cementing practices should be adopted, including the use of centralizers, scratchers, and adequate amount of cement to keep corrosive fluids away from contacting outside of the casing. • Electrical insulation of flow lines from wells by the use of non-conducting flange assemblies to reduce or prevent electrical current from entering the well. • The use of highly alkaline mud or mud treated with bactericides, as a completion fluid will help alleviate corrosion caused by sulfate reducing bacteria. b) In case of Internal corrosion, the following practices should be employed; • In flowing wells, packing the annulus with fresh water / low salinity alkaline mud / Inhibitors. • Wells having pumps like. Sucker rod and Electrical submersible pumps, the pump assembly should be placed as close to bottom to minimize the damage to the casing from corrosive fluids.

181


c) When H2S or CO2 is present in the well fluids, casing of suitable grade should be selected keeping in view the effect of corrosion cracking. 14.5 REUSE OF CASING & TUBING AFTER RETRIEVAL A) DAMAGED PIPE BODY Retrieved casing pipes should be inspected by visual, mechanical gauging and by NDT techniques e.g. electromagnetic, eddy current, ultrasonic and gamma ray. These inspection techniques should be adopted to segregate the repairable pipes keeping in view the following damages: a. Outside and inside corrosion damage. b. Inside surface wire line (longitudinal) damage c. Outside transverse and longitudinal slip and tong cuts. d. Inside surface drill pipe wear (casing only) e. Transverse cracking (tubing only) f. Inside surface sucker rod wear (tubing only) g. Casing and tubing should be classified according to the loss of nominal wall thickness listed in Table 1 Following points should be considered while going through Table 1. • Loss of nominal thickness of new pipe in the threaded portion and/or upset section, whether threaded and coupled external upset or integral joint, is not to be classified in accordance with Table 1. • Loss of wall thickness in the heavier upset sections could be permitted to higher Loss of nominal thickness of new pipe in the threaded portion and/or upset section, whether threaded and coupled external upset or integral joint, is not to be classified in accordance with Table 1. • Loss of wall thickness in the heavier upset sections could be permitted to higher percentage depending on the intended service. • Damage and /or wall reductions affecting the threaded ends of pipe require individual consideration depending on the anticipated service. The colour code identification system used to denote the other defective conditions is provided in the Table 2. The colour coding should consist of a paint band of the appropriate colour approximately 2 inches wide around the body of the pipe approximately one foot from the box end. B) DAMAGED COUPLING • Connector joints of 18 ½ “& larger size O.D. Pipes shall be replaced and casing shall be subjected to hydraulic tests. Welding procedures shall be followed as per API standards. • New coupling shall be replaced and pipes shall be subjected to hydraulic test as per API 5CT. C) REPAIR OF CASING PIPES Repair of casing pipes, should be carried out in such a way that specification of finished casing shall conform to API 5CT. Following points are to be included while carrying out the repair: • Drifting of all pipes 182

Casing Operations

• • • • • • •

Thread inspection on each pipe Thickness gauging on each pipe Checking and straightness of each pipe Hydro testing on each pipe Reconditioned pipe must conform to API standard Marking of specification on each pipe Rust preventive coating to be applied

14.5.1 Performance Properties of Used Casing There is no standard method for calculating performance properties of used casing & tubing. Performance properties should be based on a constant OD. If external surface corrosion is evident, it must also be taken into account. Small pits or other localized metal loss may not be damaging depending on the application of the pipe, but this type of metal loss should be considered and evaluated. Final rating of a length of pipe for further services requires consideration of the inside wall condition and remaining wall thickness to evaluate resistance of the body to collapse, burst and tension. Thread condition also require attention to evaluate resistance to leaks. The re -use of retrieved casing pipes after repair should be decided, depending upon the end use considering required performance properties vis-à-vis re-estimated performance properties of retrieved casing / tubing. 14.5.2 COMMON FIELD PRACTICES TO AVOID CASING & TUBING TROUBLE i. Drill pipe being run inside casing should be equipped with suitable drill pipe protector to avoid damage to casing inner wall. ii. Dropping a string, even a very short distance, may loosen the couplings at the bottom of the string. iii. Leaky joints, under external or internal pressure are a common trouble and may be due to the following; • Improper thread compound and torque • Improper cut threads and or dirty threads • Couplings that have been dented by hammering • Excessive rerunning Table: 1 “Classification and colour coding of used casing and tubing Class

Colour Bond

Loss of nominal

Remaining minimum

Wall thickness (Percent)

wall thickness(Percent)

2

Yellow

0-15

85

3

Blue

16-30

70

4

Green

31-50

50

5

Red

Over 50

Less than 50

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Table: 2 “Colour Code Identification” Conditions

Colour

Damaged field or pin end

One red paint band approximately 2 inches wide around the affected coupling or box end

Damaged coupling or box

One red paint band approximately 2 inches wide around the pipe adjacent to affected threads.

Pipe body will not pass

One green paint band approx. 2 inches wide at the point of drift restriction and adjacent to the colour band denoting body wall classification

IV. Causes of casing troubles a) Forcing casing through tight places in the hole. b) Pulling too hard on a string to make it free, may loosen the couplings at the top of the string. These should be re-tightened with tongs before finally setting the string. c) Landing the casing with improper tension after cementing leads to failure of casing during subsequent rotary drilling inside the casing. d) Drill pipe wear while drilling inside casing is particularly significant in deviated holes. Excess doglegs in deviated holes, or occasionally in straight holes where corrective measures are taken, result in concentrated bending of the casing that in turn results in excess internal wear. e) Buckling of casing in an enlarged & washed out un-cemented cavity due to release of tension in landing. f) Application of high Torque on casing, especially during breaking out, cause bending affects which lead to galling of thr.eads. V. Tubing failure a. Improper selection of type / grade of tubing, especially of non-upset where upset tubing should be used. b. Excessive sucker rod breakage c. Use of worn-out and wrong types of handling equipment, spiders, tong’s die and pipe wrenches. d. Replacement of worn couplings with Non API couplings e. In case of fatigue failure at the last engaged thread, use of upset tubing over non - upset tubing reduces chances of failure. f. Tubing that has made multiple round trips in the hole, may have pins reduced in diameter due to successive yielding by repeated makeup. This condition may reduce joint strength, leak resistance, and in severe cases lead to abutment of pin ends near center of couplings. 14.6 CASING LOWERING PROCEDURE A. Onland / Jack Ups 1. Ensure all necessary arrangements as per the check list. 184

Casing Operations

2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.

13. 14. 15. 16. 17. 18. 19.

Check accessories like shoe / collar for proper functioning before make up. Pick up first single fitted with guide shoe from catwalk using rope. Latch it in the elevator. Lower it in the hole through rotary table. Pick up the second single from cat walk with the help of crane / air winch. Latch it in the elevator. Open the protector and apply the dope on threads. Stab it in the box of first single carefully to avoid the damaging of threads. Use rope for the initial tightening of 4-5 no. of threads. Then use manual or power tongs for tightening of joints to recommended torque. Check it with the help of gauge. Lift the string. Remove the slips and gradually lower the casing pipe. In case spider slips are used, then Safety clamps may be used to avoid casing drop out from slips as it could be inadvertently opened by Derrick man. Safety clamps are no longer required when adequate casing load prevents the slips from opening manually. Ensure the flow of return mud. Continue the lowering of casing pipes keeping an eye on return mud. One man should be assigned to cross check the lowering schedule as per the plan. Fill the hole regularly as per the plan. also break the gelation of mud before entering the open hole. Attach centralizers / scratchers as per the cementation programme. Continue this procedure till the casing is lowered to the desired depth. Make up the circulating head for mud conditioning prior to cementation while circulating reciprocate the string till cementing arrangements are being made.

B. On Floaters 1. Pick up the shoe joint and set in the slips. 2. Fill the shoe joint with mud. Raise and lower the joint to check the operation of the shoe. 3. Use thread locking compound on all threads between the shoe and float collar. 4. Install casing centralizers as per casing program. 5. Fill the casing with mud and reciprocate the casing when the float collar joint is made up to ensure the correct function of the float. 6. Apply thread lubricant with the joint of casing in the “v” door. Never while the casing is set in the slips in the rotary table. 7. Fill with mud each joint of casing run and top up every fifth joint of casing run. 8. When picking up casing from the casing deck is completed check that the correct number of joints remains on deck. 9. Make up the casing hanger joint. Ensure that the running tool does not back out. 10. Remove the rotary insert bowls to allow the casing hanger to pass through the rotary table. 11. Lower the casing hanger below the rotary table and install rotary insert bowls #3. 12. Run the drill pipe landing string drift all drill pipe run. 13. Pick up the single with the bottom part of the cement head and make up to the landing string. 185


14. Install the top part of the cement head and attach two lengths of the Chikson line to the cement head. 15. Stroke open the motion compensator. 16. Open the choke and kill lines on the BOP stack and line up so they are vented to the atmosphere. 17. Pick up the slips, lower the casing string and land the casing hanger in the well head. 18. Line up the Chickson line to the rig pump. 19. Remove the elbow Chickson lines between the cement manifold and the choke and standpipe manifolds. 20. Close the choke and kill lines on the BOP stack. 21. Circulate the contents of the casing string. 22. Re-route the Chickson line to the cementing unit. 23. Pressure tests the surface lines. 24. Cement the casing. 25. Bleed down the air pressure on the motion compensator until only the weight of the landing string is held. 26. Break the Chickson line just above the rotary table. 27. Release the running tool- four turns to the right. 28. Energize the pack-off assembly to 18,000 ft/lbs.- approx. five turns to the right. 29. Pressures test the pack-off assembly. 30. Pressure test the BOP stack. 31. Pull out of the hole with the running tool and the landing string. 32. Service the universal direct drive casing hanger tool and install thread protectors. 33. Install 13.375” wear bushing. 14.7 LINER HANGER Required handling tool 1. liner as per plan plus 10% extra 2. liner shoe , landing collar 3. liner hanger with setting tool 4. liner rotary bowl ,liner slip 5. side door elevator 6. single joint elevator with lifting slings 7. jaws for manual power tongs 8. hydraulic casing tong dressed for liner with hydraulic hoses, back up line, torque gauge and power unit 9. casing dope, API modified – 1 bucket 10. liner fill up line 11. manila rope 12. Rubber clamp-on protector – 6 nos. 13. thread locking compound 14. wire brushes 186

Casing Operations

15. 16. 17. 18. 19. 20.

liner drift gauge cement and chemicals as per cementing plan circulating head with 2” x 10,000 psi hammer union connection cementing head large chain tong 16 mm x 5 mm rope sling for lifting pipe from catwalk – 2 sets

14.7.1 Procedures for Lowering Liners 1. Hang hydraulic casing tong, install back up line with torque cylinder, gauge and hydraulic hoses 2. Insert bowl in rotary for liner 3. Rig up single joint elevator with sufficient length of 16 mm or19 mm rope to the hook block 4. Rig up main elevator with links 5. Rig up liner fill up line 6. Circulating head should be ready on the rig floor 7. Check up Liner grade 8. Make up Float shoe with pipe lock compound on first joint 9. Pick up the shoe joint directly with crane to the rig floor through v-door and place it in the side door elevator. Lift the joint carefully without damaging the shoe. Set in slips, fill with mud and raise/lower joint to check operation of shoe. 10. Make up Float Collar (optional) with pipe lock on the bottom of the second joint 11. Make up Landing Collar with pipe lock on the bottom of the 2nd. / 3rd. joint as prescribed in cementation plan. Clean and apply thread locking compound. Install centralizer on body as per plan if not installed in the deck earlier. 12. Fill joint of liner immediately above landing collar, raise, lower and check. 13. Run liner with centralizers as per plan. Tighten all joints to recommended torque. Fill all the joints during running in. 14. Make up Liner hanger, Liner wiper plug and Running tool to recommended torque. 15. Further run in liner with drill pipe. 16. Run in liner up to required depth. 14.7.2 Liner Hanger Preparation 1. Take the measurement of the drill string, when making the last round trip prior to logging of the well. 2. Take the drill pipe stand count to avoid running errors. 3. Take measurement of liner, number them and drift the same. 4. Check liner hanger equipment for dimension, damage and drift. 5. Check the float shoe setting depth and overlap of liner after consulting well site geologist and tool pusher/DIC. Usually overlap should be kept 100-150 meters if well plan permits. 6. Make liner tally and drill pipe tally for liner run in. 7. Set Liner Hanger as per manufacturer’s recommendations / setting procedure. 8. Do not allow any right hand rotation as this may release the liner.

187


9. Wash the last 20 m to bottom, maximum circulating pressure should not exceed 600 psi (40 ksc) or recommended value. Locate bottom and watch out for a sudden pressure increase. 10. Install DPWP in cementing head and check. 11. Pull back to the setting depth and note the free hanging weight of string with pump on and off. 12. Circulate one cycle, until well is free from cuttings and mud is free from gas. 13. Circulate with cementing head installed on the string and string should be reciprocated during circulation. 14. Set Liner Hanger as per procedure. 15. If hanger is not set, pull back to 1 ½ feet above the liner setting depth and increase the setting pressure in stages of 100 psi, for hydraulic liner hangers. Lower string again and set liner. In some cases, slight jerking down has to be done to get the initial grip. 16. Pick up free drill pipe weight leaving 1 to 5 tons on hanger. 17. Turn string slowly right hand. Check for any increase in rotary torque. Continue turning of string until maximum of 16-20 turns. 18. Pick up drill string weight and raise 1-2 feet. Ensure that slick joint does not come out of DPOB / RPOB / Hanger seat. After ensuring that drill pipe is free from liner, lower the string and 5000-10000 lbs (2 to 5 tons) weight on the hanger. 19. Circulate for 5 minutes to ensure that all conditions are normal. 20. Pump in required quantity of cement 21. Drop the Drill pipe wiper plug 22. Displace with mud till DPWP sits on Liner wiper plug 23. Increase pressure to recommended value so that Liner wiper plug shears off 24. Displace further with mud till DPWP and Liner wiper plug sits on the Landing Collar completing Liner Cementation. 14.7.3 Precautions 1. Lower liner at moderate speed to avoid pressure surges. 2. Try to back out the running tool and retighten same with chain tong at rotary table. 3. Keep an accurate record of the various string weight 4. Calculate cement and displacement volumes as accurately as possible. 5. Excess cement slurry should be circulated out. 6. Back pressure may be applied during the initial setting of cement to avoid gas migration through cement.

188

Drill Stem Testing

CHAPTER- 15

DRILL STEM TESTING Drill stem testing (DST) is a method that is used to evaluate the sub-surface formation or reservoir, in either Cased hole or Open hole, wherein Drill stem or Production Tubing that acts as a conduit for fluid flow is also used as a manipulating tool for down hole valves. This method provides an accurate method of formation evaluation. DST requires opening of a well bore section to atmosphere or to reduced pressure. Various DST tools such as Reciprocating type, Rotating type, Annular responsive type, Dual shut-in / flow, Multiple shut-in / flow, Surface pressure read out system etc are used. The assemblies / sub-assemblies of a DST string performs the basic task of isolating the annulus and reducing hydrostatic head and allowing formation fluid to flow on its own thereby recording the flow rate and measure Shut-in pressure and temperature accurately and at the least time. This is possible because Recorders form a part of the Reservoir. DST sampler also traps Formation sample under in-situ condition. Any amount of drawdown limited to Packer rating could be given as the tool is run in closed condition. The DST assembly primarily consists of : 1. Packer – for isolating annular hydrostatic head 2. By-Pass Valve – to equalize pressure across packer and to avoid surge / swab during tripping. 3. Pressure and Temperature recorders – to record down hole pressure and temperature against time scale 4. Tester Valve – to enable the string to be run in closed condition during tripping and keep the string in open condition during testing. Opening / Closing of the valve is done through pipe movement. 5. Flow / Shut-in Valve – to enable flowing or shut-in condition during testing 6. Jar – to facilitate release of DST string in case it gets stuck 7. Safety Joint – to disengage stuck string in case jarring fails to release the string thereby retrieving the main DST tools 8. Reverse Circulating Valve – to allow communication in between string and annulus 9. Perforated Pipes – to arrest sand intrusion inside string 10. Sampler – to trap formation fluid under in-situ condition 11. Control Head – connected to the topmost pipe at surface having series of valves for controlling and diverting flow 12. Choke Manifold and Chickson Lines The schematic of a typical DST assembly is shown in Fig. 2. 15.1 PROCEDURE 1. Pick up DST assembly one by one and hand tight on rotary table 2. Tighten all the joints, both working and service, with power tongs to their recommended torques. 3. Lower the testing string (fig.3) into the hole with “Tester Valve” in closed position, to prevent entry of well fluid into drill pipe. 4. Make up adequate number of Drill collar stands 5. Connect Reverse circulating sub on top of Drill collar stand or any other position deemed fit. 189


6. 7. 8. 9.

10. 11.

12. 13. 14. 15. 16. 17. 18. 19.

20.

Make up and lower Drill pipe or Tubing pipe to desired depth Position Packer at 2 – 3 Mts. Above the zone Set Packer and inflate it Close By-Pass valve and open Tester valve that opens after a time delay giving an indication of a jerk at the Drillometer Vernier scale. During hydraulic time delay, the Vernier needle slowly looses weight indicating slow string travel downwards. First flow is given for 5 – 20 minutes depending on the formation permeability and flowing characteristics so as to bleed off the supercharged pressure Close the Shut-in valve and record shut- in pressure down below. Duration of shut-in period depends on the permeability, i.e. pressure transmission rate. Shut-in curves should cross the After Flow effect and be in the steady state condition for fruitful reservoir evaluation. Open the valve for second flow and measure flow rate through various bean sizes. Close the valve for second shut-in Open the valve, if required, for prolonged flow and flow rate measurement At least two flow and two shut-in curves are recorded. In some cases, three flow /three shutin or more are taken for proper reservoir evaluation. Upon completuion of test, open Reverse circulation valve / port and circulate out all the influx for the drill string with kill mud Open By-pass valve, Close tester valve and unseat Packer P/O the string filling up hole and monitoring flow check intermittently. After DST assembly is P/O to Rotary table, detach sampler and hand it over for PVT analysis or nipple open ports to record pressure at ambient conditions and drain formation fluid to measure Gas / Oil / Water ratio sand fluid characteristics. Break open DST assembly and lay it down cautiously and carefully.

15.1.1 Important Notes • The operation of Dual CIP (Halliburton tools) closing / shut-in is done by rotating the string, whereas opening/ closing of “Tester Valve” is done by either lowering down or by lifting up the string. In case of Dual CIP, only two flow and two shut-in’s are possible. • Multiple CIP (Halliburton) and MFE ( Flopetrol Johnston) can provide multiple flow and shut-in operations and are especially required to evaluate reservoir depletion. • Hook wall packers are used for cased hole testing wherein packer could be set at any point within the casing whereas generally Open hole packers are energized by resting string on bottom and applying compressive load. • DST packer is often the preferred technique to determine casing leakage and identifying the leakage point. • At least two recorders, one each above and below packer, are used to investigate choked string apart from acting as alternatives. • If formation fluid influx is primarily water (identified easily during testing) and the flow volume is insufficient, then sample can also be collected after breaking out each stand for finding out constant salinity. • Open hole DST is also performed, to determine water level • Gas Oil Ratio (GOR) can also effectively be found out through DST. • DST also evaluates the efficiency of cement job carried out for water shut-off or after performing cement squeeze job.

190

Drill Stem Testing

15.2 PRECAUTIONS BEFORE/ DURING DST 1. In case of Open hole DST, hole should be in good shape & condition. It is important to have a caliper log of the well for Packer Seat identification before running in the tools. 2. For open-hole test, Packer should be set against competent formation that is capable of bearing the pressure difference above & below the packer during opening of Tester/ CIP valves. 3. During DST, annular level is the prime indicator of a leaking Packer or Drill pipe. Hence, it should be always checked from time to time through out the test. 4. Hole should be kept full before tester valve is opened. Any drop in the level indicates improper seating of packer during which annulus fluid shall rush into the string due to huge pressure differential owing to U-tube effect. 5. Follow good safety procedures during the total test duration. Line up cementing unit through Kill line and arrange adequate volume of Heavy weight mud before running in for contingency well killing measures. 6. Follow IWCF Well Killing/ control procedure, if well killing is required. 7. Choose the correct time interval for flow & closed-in pressure periods, after observing the well’s ability to produce during first flow. Allow the Shut-in curve to reach steady state condition so as to extrapolate it later using Horner’s method for proper reservoir evaluation.. 8. Carry out flow measurements, if well flows, using various bean sizes. 9. Floor manifold and Chickson lines should be properly anchored with the help of chains attached to the Chickson lines. 10. Initiation of well flow, i.e. opening of Tester valve, shall preferably be done during day time. However, it can also be done at night with adequate lighting arrangement. 11. Fill up water cushion inside string after every 5 – 10 stands allowing passage for air displacement. Water / N2 cushion should be given as per required pressure drawdown. 12. A high viscous mud pill of 1 – 2 stands could be given inside drill string before water cushion to avoid choking of DST tools due to accumulated solid scale particles of drill pipe interior during water fill up. 15.3 CHART INTERPRETATION DST chart produced by a recorder, is a record of bottom hole pressure Vs time, during flow of formation fluid and shut in (fig. 4). Maximum information about reservoir is studied on the basis of the patterns & readings of the chart only. Following interpretation can be obtained from the chart that is generally carried out by Reservoir department: Production : Expected production rate of oil and gas and GOR (from Sampler). Permeability : Direct means of evaluating average effective permeability vis-à-vis actual formation fluid produced Well Bore : Extent of well bore damage or skin effect so as to decide well stimulation Damage stimulation measures, if any, for improved Productivity Index (PI). Reservoir : Calculates static reservoir pressure. Pressure Depletion : Detect depletion so as to differentiate between big reservoirs and small reservoirs (commercially not viable). 191


DRILL PIPE

DRILL PIPE LIFT NIPPLE HOLLOW PIN IMPACT REVERSE SUB

ADAPTER BAR DROP SUB

BAR DROP SUB

DRILL PIPE OR DRILL COLLARS

REMOTE CONTROL SAFETY VALVE

DUAL CLOSED IN PRESSURE VALVE

FLOW TEE

MANIFOLD FLOW LINE

MANIFOLD FLOW LINE PRESSURE BALANCED SWIVEL MASTER VALVE

HANDLING SUB A CHOKE ASSEMBLY (OPTIONAL)

HYDRAULIC CONTROL LINE

HYDROSPRING TESTER

LT-20 SWIVEL

BYPASS - PORTS

MASTER VALVE

NIPPLE DRILL PIPE

REVERSE CIRCULATION PORTS

B.T. PRESSURE RECORDED (A.P. TYPE) HYDRAULIC JAR

ACCESS VALVE

V R SAFETY JOINT BY-PASS PORTS EXPAND SHOE PACKER ASSEMBLY

NIPPLE

(a)

DRILL PIPE

ANCHOR PIPE SAFETY JOINT FLUSH JOINT ANCHOR HT 500 TEMPERATURE RECORDER BT PRESSURE RECORDER (BLANKED OFF)

Fig. 1 Two Typical Systems of Surface Equipment for an Open Hole Land Test

Fig. 2. One Hole Single Packer Test Radius of Investigation Reservoir Analysis

:

Barrier Indication

:

:

The radius of the Reservoir which has been investigated during the test period. Radius of reservoir that has been investigated during test period. Useful for determining well spacing requirements and other volumetric calculations. Barrier or any other anomaly can be detected such as existence of different fluid contacts, faults etc.

192

Drill Stem Testing

Fising Neck Choke Circulating Valve Cup

Locking Mechanism

Testing Valve

BT Pressure Recorders

Bypass Valve

RTTS Packer

RUNNING IN

OPEN FOR TEST

TAKING FIRST C.I.P.

OPEN FOR TEST

SUBSEQUENT REVERSING C.I.P. RETRIEVABLE VALVE

Fig. 3: Hydrospring Retrievable Valve Tester

193

TREATING FOR SQUEEZING


Diagrams

Above Packer B.T.

Blanked-Off B.T.

291 537

B.T GAUGE NO.

TICKET NO.

INITIAL

EXTRAPOLATION PRESSURE GRAPH

FINAL

(a) PRESSURE RECORDER CHARTS SHOWING A BARRIER

(b) EXTRAPOLATION OF PRESSURE BUILD-UP CURVES INDICATING A BARRIER

Fig. 4

194

Drill Stem Testing

Two of the ways of making up the Unitest Tree surface control equipment are as follows : (from Top to Bottom) (1) (2) A B C E D G F H H I

A - Lift Nipple

B - Adapter C - Bar Drop Sub

D - Bar Drop Sub

S-15 Manifold Flo-Thru Manifold is not shown E - Remote Control Valve

F - Pressure Balanced Swivel

G - LT - 20 Swivel H - Master Valve

H - Master Valve I - Quick Disconnect

Fig. 5 components of the unitest tree 195


CHAPTER - 16

CORING The 60 feet core barrel consists of two sections- (a) Upper sections & (b) lower sections (fig-2). The upper section contains safety joint with an API box connection, swivel assembly and top stabilizer, the bottom section of barrel have two stabilizers and an elevator sub at top, core head pin connection and core catcher at lower end. 16.1 CORE BARREL ASSEMBLING • Before picking up barrel sections ensure that all outer tube connections are sufficiently tight to prevent backing out in the derrick while assembling. • Pick up lower section (fig. 2b) and tighten thread connections to the recommended torque using rig tongs and rope on cathead and lower in the rotary table. Avoid setting slips or placing tongs on box connections (fig. 3). Note: Bottom Protector must be tight. • After making middle stabilizer place drill collar clamp above slips, below middle stabilizer. • Back out elevator sub from outer tube using chain tongs. • With inner tube still connected to the elevator sub. Pick up inner tube approx. 6-9 inches. • Make up inner barrel clamp to the inner barrel leaving sufficient space above on inner barrel box connections (fig. 4). • Back out elevator sub taking care not to damage inner tube connection. • Place core barrel inner and outer tube protectors on elevator sub. Make up API connection turning the sub upside down on elevator sub to connection on the top section of core barrel. • Pick up upper section in elevators. • Remove bottom protector, exposing inner barrel. • Remove inner tube thread protector. • Make up upper and lower sections of inner barrel. Tighten with chain tongs using cheater bars. • Pick up on elevators and remove inner tube clamp. • Make up outer tube connections using chain tongs. • Finally tighten to recommended torque with rig tongs. • Lower core barrel, torque up top stabilizer and safety joint cross over sub above stabilizer. • Reset slips as near as possible to top stabilizer, allowing sufficient space for drill collar clamp. • Back out safety joint using chain tongs, remove inner barrel from outer. • Check core catcher is present. Also ensure core marker is present. 196

Coring

• • • • • •

• • • • • • • • • Barrel

Tighten inner tube shoe lower and upper halves using chain tongs and cheater bars. Run inner barrel back into outer tightening middle connection, top connection (at swivel assembly) and all connections on swivel assembly. Make up safety joint fairly tight. Pull assembled barrel out of the rotary table. Break off bottom protector and check lead.(fig. 5,6,7) For adding or removing shims, run barrel back into rotary table .Set slips below top stabilizer, make up collar clamp and back out safety joint, pick up until 8 inches of inner tube is exposed. Put inner tube clamp on inner barrel. Back out cartridge cap and add or remove shims as necessary.(fig. 8) Once spacing is corrected, pick up, remove inner tube clamp and make up safety joint with chain tongs. Torque safety joint to recommended torque with rig tongs. Pull barrel out of rotary table, take off protector and check lead using CB gauge. Make up core head. Check rotation of the inner tube. Run core barrel back into rotary table. Set slips below blades of top stabilizers. Ensure steel ball is not in ball seat. Pick up required cross over or drill collar and make up to API torque rating. is now ready to be lowered.

16.2 CORING PROCEDURE Preparation • On the last bit run prior to coring, run the junk sub to clean the hole from any junk. Incase of doubt run reverse circulation basket or magnet to ensure complete removal of junk from bottom. • In case of dog legs, tight spots etc. in open hole, circulate the hole thoroughly and make wiper trip before coring to avoid sticking of core barrel. • Select core head based on previous experience, bit records and formations to be drilled. • Check core barrel connections with drill collar for its compatibility. If not ensure cross over is available. • Ensure availability of adequate number of drill collars for giving sufficient weight. • Run adequate number of stabilizers to keep core head steady on bottom. • Volume of mud to be circulated will be determined by mud type, depth of hole, pumps and type of formations drilled. • Avoid mixing LCM in large quantities which could possibly block core barrel or core head fluid passage. • When starting coring, a slow rotary speed of 40-50 should be applied and gradually it can be increased. In general a rotary speed of 70-120 RPM is sufficient to core most formations. • Weight on bit will be determined by size of bit, size of core barrel and nature of formation to be cored. When starting coring apply minimum weight and then increase in small increment (1-2 Ton) until optimum performance is achieved. Do not use more than recommended weight on bit for the specific core barrel. • Use correct combination of weight and rotary speed to avoid excessive or fluctuating torque. • Ensure that there is no restriction in the string to stop passage of pressure relief plug ball. 197


• • • • • • • • •

Check pump liners and stroke for desired flow rate. Figure 8 On reaching bottom make up Kelly and start circulation with recommended flow rate (note down pressure) at least one single before drilled depth. Abnormally high pump pressure indicates that there may be debris in the barrel or core catcher and it should be cleared before starting coring. Wash down to bottom and watch for tight spots. Tag bottom and mark Kelly. Lift 2-3 feet off bottom, circulate for 5-10 minutes. Run back to bottom and check Kelly measurement. Wash down slowly picking up periodically and checking Kelly measurements with pipe tally. When true bottom is reached a WOB gain accompanied by a pressure increase will be noticed. 198

Coring

• • • • •

Once bottom is reached circulate for another 10-15 minutes to clean out inner core barrel. Pick up, break off Kelly and drop steel ball, add spacer sub, if necessary. Make up Kelly. Start circulation, again note circulating pressure. Pump ball to bottom, when ball seats on pressure relief plug a slight pressure increase will be indicated. Record final off bottom pressure with ball seated.

16.3 CORING OPERATION • Check pump strokes to ensure correct circulation rate is delivered to core head. • Lower barrel until minimum starting weight is reached. • Start rotary and bring it slowly to 40-50 RPM. • When bit has touched bottom maintain starting weight till one foot has been cored. • Then increase the weight slowly in 2000 lbs. increments. • Increase rotary speed to approx. 60 RPM. • When two to three feet has been Cored, weight and RPM can be varied to achieve maximum performance. • Record pressure and maintain it throughout the coring. If there are large variations, it should be immediately analyzed and corrective action should be taken. 16.3.1 Possible Causes of Pump Pressure Change Pressure change could be due to changes in flow rate, debris in pump valve seats or washed liner. First check pumps strokes and condition. • Pressure decrease could be due to core jamming or filling of core barrel. Or it may be due to wash out in drill string. Then pull out of hole. • If pressure increases then either bit has been damaged (If on lifting bit off bottom the pressure returns to normal and on retagging bottom it increases immediately then bit is damaged) or due to inner barrel or swivel assembly backing out and sitting in core head. It can be found by lifting string off bottom as in this case most likely pressure will remain high. • Minor fluctuations in pressure can be due to changes in formation, while mud is being mixed or unbalanced mud in hole after a trip. 16.4 CORE BREAKING Stop rotary table and shut off pump. Mark the Kelly. • Pick up Kelly until weight indicator shows core has been caught, continue picking until core breaks (this will be indicated by reduction in string weight – with a sharp reduction in string weight once core is broken) or an over pull of 20000 lbs. is reached. If core does not break at this point then circulate at normal coring flow rate, maintaining pull until core breaks. • Pick up approximately 10 feet, then lower slowly back to one feet off bottom, watch the weight indicator, making sure that barrel goes back to bottom without meeting any obstruction caused by core left in hole. • To resume coring after connection, run to bottom without rotary or circulation and add approx. 50% higher than normal coring weight. This additional weight will release the core from the core spring, permitting the passage of new core into the core barrel. • Lift the drill string until normal coring weight is reached. Start pump at normal rate. Bring rotary up slowly to normal rotation and continue to core. • Ensure that pump pressures are normal when coring recommences. 199


16.5 RECOVERY PROCEDURE • Break core and pull out of hole. While pulling out set slips slowly on rotary to avoid jarring the barrel as core loss may occur. • When core barrel reaches surface put collar clamp above slips. • Break off last stand of drill collar and stand it in derrick. • Remove steel ball from the core barrel using pick up tool. • Make up elevator sub, torque up sub using rig tongs. • Pull core barrel out of rotary table. Break off bit. • Make up core barrel protector tightly. • Run core barrel back into rotary table and visually inspect core barrel, stabilizers etc. • Set slips below top stabilizers, replace collar clamp. • Break out safety joint, rotate out using chain tongs, pull out inner barrel. • Break off inner tube shoe lower half ( catcher) using chain tong or pipe wrench.(fig-9) • Place core tong shoe on inner barrel. The shoe should be backed out on the rig floor preventing core from falling out of the inner tube.(fig-10,11) • Put core tong handle on core tong shoe. Exert pressure on core tong handle and pick up inner barrel slowly. • Remove the inner tube shoe. Now the core can be removed from the inner barrel as inner tube is picked up. • When desired boxing length is reached exert pressure on core tong handle to break core. The exposed core then can be removed and boxed. • Lower barrel, keeping pressure on core tong handle until core in core tong is resting on the floor. The pressure on the core long handle can now be released. • Pick up inner tube again exposing core. • Continue this procedure until core marker comes out of the inner tube. • If core marker or further core does not appear, lower inner tube onto floor and knock inner barrel with sledge hammer until core falls. • Do not repeat the sledge hammer blows to the same area on the inner barrel as this will damage the tube. • If still core cannot be removed then lay down inner tube and pump out core. Use pump out bean and plunger with water as medium to pump out core. In no case pressurized air should be used. • After complete removal of core, clean off core catcher and lower shoe, replace if necessary, make lower shoe up onto inner barrel, and tighten with chain tongs using cheater bars. • Run inner barrel back into outer tubes. • Check bearings and “O” rings if defective, replace them. • Regrease safety joint and make up to recommended torque. • Break off protector. • Check core head wear change out, if required. • Make up core head. • Pick up barrel. Ensure inner barrel is rotating freely, by placing hand inside core catcher and rotating. • Now barrel can be lowered back into hole for further coring. • In case of fiber glass inner core tube, coring is performed in exactly the same manner as coring with conventional steel inner tubes. After laying down the inner tube, fiber glass tube 200

Coring

• •

can be cut into sections at the rig and then sealed with plastic caps at end and sent to lab for testing. In fiberglass inner tube pin threads are molded on both the upper and lower ends which will accommodate internal flush connections. Available sizes for fiber glass inner tube are- 6-3 / 4" x 3", 6 – 3 / 4 “ x 4“, and 8” x 5 1 / 4“

Precautions while coring • Inspect the coring equipment thoroughly (e.g. core catchers, core barrel, bearing, swivel assembly etc.) for straightness before starting coring. • The hole should be free of junk at the bottom otherwise it will result in worn out diamond core head. • Avoid reaming with core bit through tight zones while running in. • Avoid drilling with roller core heads as there is no provision for efficient cleaning as in jet bits. • Tight pulls while pulling out and the attendant rotations, jerks and reciprocations to release it, should be avoided as it may cause the core to slip down. • Try to prevent drill string vibrations while coring. • Unless the coring is complete or otherwise warranted by bad condition of hole, the bit should not be lifted off-bottom. • Adhere to uniform feeding of WOB for better core recovery. • Breaking off the core should be done as per the norm.

201


16.6 CHECK LIST FOR CORING OPERATION • Check the core barrel for crookedness, worn out threads, severe dents etc. • Check the core catcher for defects. • Check the vent valve and if the ball or seat is worn out, replace it. • While making up the complete core barrel assembly, check looking from one end, whether the same is straight or bent. • Check the roller cutter head for rollers and worn teeth. • During round trip, before coring, check the condition of hole for any tight pull. • If there is any junk in the hole, fish it out before starting coring operation. • Check the Kelly and drill pipe stand for crookedness. • Check mast centering if it is not proper it may cause drill string vibration while coring. 16.7 CORE BARREL SERVICING After the initial make up of the core barrel, it should be checked at regular intervals for wear of thrust bearings, bearing retainer cartridge cap and plug, “O” rings, pressure relief plug, inner tube shoes upper and lower, and core springs. A. Swivel Assembly1. Replacement Of Thrust Bearings• After every core check for bearing wear. • Rotate inner barrel at inner tube plug, if rotation is difficult or rough it indicates that balls have broken. • Secondly check for vertical movement .If excessive this also indicates worn bearing and should be changed. • Even after changing bearing if vertical movement exists then check wear on bearing retainer, cartridge plug and cartridge cap. • To save rig time and loss of core it is suggested to change bearings after 3-4 cores. 2. Changing Bearing (fig- 14, 15) • Break out safety joint. • Pick up inner tube; place inner tube clamp on inner tube as shown. • Using spanner wrench back out cartridge plug. • Pick up safety joint exposing bearing and bearing retainer. • Before breaking out bearing retainer place rags etc around slips to prevent balls dropping back into hole. • Back out bearing retainer and change bearing . • Clean and dope retainer, hammer up. • Clean and re dope all threads and make up cartridge plug ensuring it is tight. B. Changing Pressure Relief Plug (fig-16,17) • Set inner tube clamp as shown. • Break out inner tube plug. • Break out pressure relief plug. Lay safety joint on floor to do this. • Check ball seals and change out, if necessary. • Clean and dope all threads and make up inner tube plug. 202

Coring

203


C. Safety Joint i) “ O” RINGS • Check condition of “O” rings regularly and change them when they are damaged. • “O” rings can be changed while changing bearing or after core recovery by sliding them up while inner barrel is being lowered back into outer barrel. ii)

FRICTION RINGS • Ensure that friction ring is free moving, clean it with diesel if it becomes clogged up.

D. Inner Tube Shoes (Upper & Lower) and Core Catchers (fig-18) • Check threads on inner tube shoes and general condition at every core- change if required. • Ensure that core spring is in good condition. • Make sure that tungsten grit has not been worn flat. DO’S AND DON’TS • Inner core barrel should be always be coated with chain oil before laying down. • Keep circulation rate around 16-19 lt/ sec. for coring – which is an optimum flow rate. • Make up all joints of inner barrel using chain tong only and check inner tube threads. • Check vertical play in bearing. It should be less than ¼” . • Check swivel joint for free rotation. • Check length or inner tube shoe lip, from bottom of outer tube sub with the help of gauge supplied. • Keep the steel ball outside while running the core barrel into the hole. • Circulate one foot off bottom at least for half an hour for cleaning bottom before starting coring operation. • Do not change the bearing on rotary as the steel balls of thrust bearings may fall into the hole. • Do not run in the core barrel without adjusting shims in case the length of the inner tube shoe lip below outer tube sub is not as per recommendations .It may affect core recovery. • Do not push the core head down through tight spots. Ream if necessary. • Do not keep barrel in hole if appreciable decrease in penetration rate is noticed. • After core recovery do not keep the core marker out side. It should be kept inside the core tube. • Do not forget to crack all joints of core barrel before laying down. 16.9 RECOMMENDED MAKE UP TORQUE FOR “CHRISTENSEN CORE BARREL” SR.NO.

CORE BARREL SIZE

RECOMM. MAKE UP TORQUE (FT.LBS.)

MAXIMUM PULL (LBS.)

1

4–1/8“

3,00

101, 400

2

4–1/2“

5,00

194, 700

3

4–3/4“

5,00

137, 400

4

5–3/4“

5

6 – 1 / 4 “ X 3”

6 7 8

8“

7,00

183, 000

15,000

290, 000

6–1/4“X4“

8,000

193, 500

6–3/4“

9,500

275, 000

20,000

322, 000

204

Directional Drilling

CHAPTER - 17

DIRECTIONAL DRILLING Directional Drilling is usually accomplished (at shower depth) by jetting using a jet bit with one large size nozzle and two blinds or by a mud motor with a bent sub or an adjustable bent housing, depending on the type of formation to be drilled. Prior to the start of any directional well a pre spud meeting should be conducted. The directional drilling plan for the well should be discussed and following topics should be included: • • •

Wells that may be approached during the course of drilling a directional well to avoid collision. Directional drilling procedures and surveying requirement that will be used to maintain adequate well to well separation. HSE issues regarding the survey winch etc.

It must be verified that all personnel directly involved with carrying out the directional drilling operation are aware of all important aspects of the operation. This is especially critical following a crew or tour change. In this regard a brief report regarding the well being drilled and behavior of the well may be handed over to directional driller to help the reliever to take quick and correct decision immediately after reaching the site. 17.1 RESPONSIBILITIES 17.1.1 Directional Driller The Directional Driller is responsible for drilling the well and performing directional survey calculations, proximity checks and ensuring that correct survey correction factors are applied to each survey in accordance with well programme requirements. He is to liaise with all responsible personnel during drilling operation. The Directional Driller is also responsible for The BHA to be run into the hole is given by directional driller. The Driller and Directional Driller are responsible for the dimensional inspection of the BHA. Directional driller may be called on the rig floor whenever a BHA is made to be run in the well. It must be ensured that BHA has the correct length of non-magnetic components to prevent magnetic interference while using magnetic survey instruments. The gauge of bit to be run into the hole and integrity of nozzles should also be checked. 17.1.2 Tool Pusher / DIC • Directional driller must be called on the rig sufficiently before the kick off operation begins. • Directional driller must be informed before any pull out of the hole is made due to any reason to avoid any extra trip for change of the BHA which may be required during next run. • The bit change program must be discussed with directional driller so that it can be clubbed with BHA change program if possible. 17.1.3 Driller/Assistant Driller Drilling parameter given by directional driller during the course of drilling a well must be strictly followed to avoid any extra trip for the control of well path. He must help the directional driller in making survey barrels and in lowering it into and pulling out of the hole. Directional Driller must be called on rig floor when the required survey depth is reached. 205


17.2 DEVIATION CONTROL Causes of hole deviation 1. Formation properties 2. Improper mechanical arrangements of bottom hole assembly. Drilling a straight hole • Drill with packed hole assembly i.e. drill with stabilizer above the bit and stabilizers in the string (given in tables later). • To avoid angle build up when using a near bit stabilizer place the near bit stabilizer immediately above the bit and place a string stabilizer 10 to 30 feet above the near-bit stabilizer. A third stabilizer at a distance of 30 feet from the second stabilizer may also be used which gives still better results. If Angle Builds due to dipping formations • Restrict the rate of angle build with a packed BHA. • Before maximum permissible limit of inclination is reached (normally 3o-5o), drop angle by changing the BHA to a pendulum BHA and continue drill with reduced weight on the bit. • Drill 40-50 metres. • Ensure the angle drop by survey. • If clear trends are observed continue drilling with desired drilling parameters till the required inclination is reached. • If inclination does not drop, use high rotary speed with reduced WOB to enhance pendulum effect. 17.2.2 • • •

Precautions At least two sets of survey instruments should be available on rig. Ensure both the sets are functional by using them regularly. Reaming is acceptable to reduce angle but to avoid unscrewing the drill pipe due to doglegs higher in the hole., the following should be taken care of : Use minimum BHA required. Do not stop rotary abruptly, slow down gradually before stopping. Use rotary brake to stop backlash. Dogleg should be worked out as per well plan. Don’t use dull bits as these contribute to an increase in hole angle in crooked hole formations. On floaters, deviation in 36” hole should not exceed 1-1/2 degrees. Use of “average angle” directional survey calculation method in the field is acceptable. However, the “radius of curvature” or “minimum curvature” method should be used to prepare the final directional report.

17.3 DIRECTIONAL DRILLING AIDS 17.3.1 Stabilizers 1. All the stabilizers should be full gauge. However a slightly under gauge stabilizer (up to 1/ 8” or lesser) at 90 ft. or higher) may be considered as full as gauge. 206


2. Stabilizers should be gauged in each round trip 3. As a rule, cement drilling inside casing should be done with slick assembly. 4. Stabilizer should have either: Open design (Vertical Holes) - 3 blades having a wall contact of + 1400. or Closed Design (Deviated Holes) - 3 blades having wall contact of 360o. 5. If the formation have tendency to develop key seats, a stabilizer having 360o wall contact placed at the top of collars is often helpful. 6. The bottom 90 feet of BHA should be appropriately stabilized for proper control in a directional hole. 7. Integral blade near bit stabilizer is preferred during jetting. 8. Stabilizers should have A Brinell hardness between 300 and 321. 9. The inside diameter of the stabilizer should preferably be the same as the inside diameter of the drill collar string. 10. Preferably the near bit stabilizer should have a box down to avoid cross over. Precautions 1. Stabilizers are often the source of high torque. Generally torque developed by stabilizers will fluctuate widely. The common practices of controlling torque are: a. Use more number of heavy weight drill pipes and accordingly reduce No. of drill collars. b. Use non-rotating blade (rubber) stabilizers. These stabilizers are generally acceptable for straight holes, but have a short life span in some formations. c. Reduction in rotary speed &WOB to control torque is not recommended. d. Condition the drilling fluid to have high lubricity & low solids. 2. Restrict the drilling torque to less than the make-up torque applied to the weakest connection in the drill string. 3. Torque developed by extremely large hang-down weight below a dogleg or kick-off point can be reduced by: a. Using a full string of smaller drill pipe (e.g. using a 4-1/2:” O.D. drill pipe to replace 5” O.D. Drill pipe.) b. Using a smaller string on bottom (tapered string). c. Using an oil base mud when conditions are severe. The torque meter on any rig should be calibrated at least once per well. 17.3.2 Preplan Slot selection for a particular well should be done according to the target direction of the well. • Wells which require more drift or inclination should be allotted outer slots and those with lesser drift the inner slots. • It is also important to see the direction of the well. Slot should be selected so that the distance between the well increases as they are drilled. • Central slot may be selected for vertical well. 207


17.3.3 Kop Selection Procedures • On Offshore platforms if most of the wells have approximately same drift in different directions their KOPs must be varied at least by 10 or 20 m to give the wells some initial separation to avoid collision of the wells directly underneath the platform. • KOP must be selected in relatively softer formations. • KOP selection for a given well also depends on the TVD and drift of the well and directional technique used. KOP must be selected so that the angle required to hit the target is at least 20o or more. 17.3.4 Checking of Instruments/Equipments • Functioning of all single shot & multishot instruments. • Functioning of survey winch and its proper grouting for on land operation. • Functioning of sand line • Availability of down hole motors, NMDC, UBHO, stabilizers, stabilizer sleeves, short drill collars, bent subs, HWDPs and other required subs. 17.3.5 Procedure for Muleshoe (UBHO) Sub Sleeve Alignment 1. Lower the deflection tool (Jet bit/Mud motor bent sub assembly) and the Muleshoe sub through the rotary table. 2. Set the slips keeping the set screws of UBHO sub above the slips. 3. Back off the Monell drill collar above the UBHO sub. 4. Loosen the set screws in the UBHO sub. 5. Align the key of the UBHO sub with projected scribe line of bent sub or open jet and tighten the set screws of UBHO. 6. Check the Muleshoe sleeve with key alignment wrench by rotating it in either direction to ensure that sleeve doesn’t slip. Orientation Procedure 1. When the kick off point (KOP) has been reached, conducting a multishot survey is preferred to determine the condition of the well bore from surface to kick off point. 2. Once the bit reaches bottom directional survey should be conducted to ascertain the tool face. 3. Based on directional survey orient the tool face in the desired direction. 4. Take a check shot survey to confirm tool face setting. 17.3.6 • • • •

Positioning Compass in the Nonmagnetic Drill Collar Select the length of NMDC & decide positioning of compass using standard guide lines. Use extension bars in the lower section of survey barrel to space compass in NMDC. Do not consider the length of muleshoe stinger for deciding the position of compass in NMDC. Orienting snubber is 9” long, so add this 9”to extension bar length for calculating the position of compass.

208


Alignment of the scribe line on the compass face with the keyway of the Mule Shoe Stinger After determining the appropriate length of extension bar, connect the mule shoe stinger to the lower end of it and connect the orienting snubber to the upper end. Align the scribe line as follows: 1. Project a vertical line from the top of the keyway, up the lower extension bar, to the T-head of the orienting snubber. 2. Loosen the set screws of T-head of the orienting snubber. 3. Align the T-head and the compass face with the projected line from the top of the keyway so that the scribe line 180o away from the keyway. 4. Tighten the set screws Insertion of Tattle tale (Lead Pin) into the Mule Shoe Stinger Before survey barrel is lowered into the drill string a tattle tale (Lead Pin) is inserted into the hole at the top of Keyway of Mule shoe stinger to make sure that blade /key of the mule sub has reached the key way. After survey barrel is retrieved the tattle tale should be bent or crushed. 17.4 RECORDING OF SINGLE SHOT SURVEY 1. Load the single-shot instrument 2. Set the mechanical clock and synchronize the surface watch or use monel sensor in survey instruments. Check it with monel ring on surface. 3. Put the single-shot instrument onto the T-head of the oriented snubber. 4. Insert the single-shot instrument into the protective casing. 5. Connect the protective casing and survey barrel and tighten the same with wrench. 6. Always use drill pipe thread protector before lowering the survey barrel into the drill string. 7. Lower the Survey barrel assembly inside the drill string through wire line /sand line to take survey. Rubber guide fingers must be inserted into the holes of mule shoe stringer/bottom shock absorber and finger guide holder installed above the protective casing. • Once kick off operation is over normally a packed hole assembly is used. For this another survey barrel is used. The required length of the extension bar must be calculated using charts. • Use internal shock absorber in place of orienting snubber and bottom shock absorber in place of mule shoe stringer. • Mule shoe sub is removed and a baffle plate is put below the non magnetic drill collar. A short piece of pipe (OD equal or slightly lesser that OD of Drill collar) may be welded at the centre of the baffle plate. It will prevent the baffle plate from tilting when survey barrel sits on it. 17.4.1 Reading of Single Shot Survey a) Holding the reader 1. The reader must be held in such a way so that the arrow which indicates hole direction points up. 209


2. When held correctly, the word “left” should appear on your right-hand side, and the word “right” should appear on your left-hand side. It is because when a picture is taken of the face of the compass during survey, it results in a reverse image. In order to correct for this reverse image, left and right are reversed on the reader. b) Placing the single shot record on the reader 1. The hole direction line on the reader passes through the center of the concentric circle and through the center of the crosshairs on the survey record. 2. The number and letters on the survey record are oriented in the proper fashion. The numbers 1 through 8 between the N and W are in forward order and while moving towards right on the picture i.e. towards right or East of N North) the numbers are in reversed order as shown in fig. below.

c) Reading single shot survey 1. Read number of concentric circle/ curved line under the cross hair to indicate the inclination of the hole with the least count of 1/40. 2. Read the position of the straight line under the hole direction line on the reader to indicate the direction of the hole with the least count of 1/20.. 3. Read the position of the long line of the cross hair on the edge of the reader in degrees with respect to left or right to indicate T.F. (Tool face) with respect to hole direction. 4. Orient the tool face in desired direction. d) Procedure for determining toolface 1. Place the survey record in the reader correctly. 2. Read drift angle and hole direction in the usual manner. 3. Take the reading long line of cross hair from the edge of the reader on left or right side asthe case may be. This will indicate tool face in degree left or right of hole direction. 210


Example: (refer fig. given above) Details as read from above figure: Inclination 4-1/4o

Direction N17oW

Tool face 115o R

R denotes right side. Tool face is 115o right of hole direction N17oW or tool face in S82oE direction. e) Correction of magnetic declination Magnetic Survey which is read by the reader must be corrected for declination (East or West available from geological office. Methods for applying correction for East/West declination 1. For East declination rotate the observed direction in clock wise direction by an amount equal to degrees of east declination and find the corrected direction. 2. For west declination rotate the observed magnetic direction in counterclockwise direction by an amount equal to degrees of west declination and the corrected direction. 17.4.2 Survey Calculation Method Though minimum curvature method gives most accurate results, average angle method may be used in field because it is easier to calculate survey data by this method using scientific calculator and it generates fairly accurate results. Note : When kick off is done by a mud motor, assembly is pulled out of hole even if maximum angle may not be achieved after the desired direction has been achieved. After this, build up is done by using a near bit full gauge stabilizer into the string. Rotary assemblies normally have right walking tendency. It is therefore, recommended that before the kick off assembly is pulled out of the hole, the direction of the well should be kept slightly towards the left depending upon the field behavior. Sometimes well may travel towards left due to formation characteristics, in such cases the well direction is kept slightly towards right. 17.5 DRILLING WITH MUD MOTOR For proper working of mud motor care should be taken regarding mud properties.Following points should be considered: 1. Sand and solid contents should not be more than 2% by volume or as indicated by the manufacturer. So desilters should be continuously used while drilling with a mud motor. 2. Rags etc. accidentally dropped down the system into the circulating system can plug and damage the motor. Always use a mud filter below the Kelly. 3. The elastometers of PDM gets damaged when oil based mud is used. 4. Operationally PDM has a working limit of bottom hole temp. upto 275oF. 5. The mud motor is designed to handle lost circulation materials but particle size should not exceed the recommendation of the manufacturer. 17.5.1 Operational checks 1. Lifting sub should be used for picking up motor. 211


2. Check axial play of the bearings. 3. Hang the motor freely and measure the distance between the lower end of bearing housing and drive sub as X1. 4. Rest the PDM down on the rig floor and measure the same distance as X2. 5. Calculate (X1-X2). It should be within limits as tabulated below: Tool Size (diameter in Inches)

Allowable Max.play (X1 - X2) in mm.

1¾

1.3

2 3/8

1.7

2¾

2.5

3¾

4

4¾

4

6¼

6

6¾

6

8

8

91/2

8

11 -1/4

8

6. Set the mud motor in rotary table, using safety clamp. 7. Check dump valve for its easy operation using wooden handle of hammer.It should be free. 8. Test the mud Motor by connecting kelly. Test should not be performed for more than 15 minutes. 17.5.2 Drilling Generally a string with a PDM can be run into the hole like a standard bottom hole assembly. When a deflection device (Bent sub) assembly is used, special care must be taken when passing the well head, casing shoe, liner hanger etc. Note : If reaming becomes necessary when tripping into the hole, extreme care should be taken, especially if diamond bits are used. When the bottom is reached, the PDM is started as follows:• Pick up the bit to a distance of 1 to 2 feet (0.3-0.6 m) off the bottom. • Start the mud pumps and increase the number of strokes to the desired flow rate. • Record the total pump pressure and flow rate.(Off bottom pressure) • After thorough circulation, lower the bit and tag the bottom and increase weight on bit slowly. After one meter is drilled, increase weight on bit. Pump pressure will rise with increasing weight on bit. The differential pressure created simultaneously must not exceed values on manufacturer’s recommendations. 212


In case of Drilling with PDM stand pipe pressure gauge acts as WOB indicator. Bit weight variations, formation changes and bit wear will change the torque at the bit. This is indicated by an increase or decrease in stand pipe pressure. A sudden rise in stand pipe pressure occurs if the PDM stalls. If this happens, pull the bit off bottom. After the pressure decreases, the PDM and bit should be lowered carefully to the bottom again and drilling is commenced. In order to drill with constant speed and torque, keep the flow rate and pump pressure at a steady level. Since the speed of the motor directly depends on the flow rate, the bit RPM will remain constant, as long as the flow rate is kept constant. 17.5.3 Testing of Mud Motor • A Screen should be used during surface testing • Before starting the pumps it should be ensured that bypass valve ports are below the rotary table. • Slowly increase the pump speed and note the flow rate & pressure drop across the motor at which by pass valve closes. • While by pass valve is in closed position, lift the motor above the rotary table until the by pass is accessible and checked for any leakage from the ports, indicating faulty seals. • Test the motor at different flow rates (at least 3 values) within the expected working rangeand note down the corresponding pressures. The amount of flow through the bearing should also be noted. A small amount and flow should be through the bearings. A back up line should be fitted over the stator during testing at surface to prevent back torque. • After making allowances for surface equipment pressure losses and mud weight, the pressure should be in accordance with the performance curves. • Lower the by pass valve below the rotary table before the pumps are shut off. After testing of the motor, motor assembly can be made up for lowering into the hole. The pressure drop across the bit nozzles for specified mud discharge should be minimum or as per the manufacture’s recommendation. Minimum back pressure of 500 psi will force the mud to lubricate the bearings. The pressure drop beyond the maximum recommended pressure may reduce the bearing life. Precaution • As PDMs will permit circulation only when rotor is rotating, idle circulation for mud conditioning should be kept to a bare minimum period. • Excessive WOB will stall the motor. Stalling will be indicated by sudden increase in stand pipe pressure. Lift the motor immediately when pressure shooting is observed. Repeatedstalling damages the elastomers. • While drilling with PDM a screen should be used below the kelly in the drill pipe. When adding next drill pipe this screen should be removed and kept in the new drill pipe which is added. • While drilling with mud motor a left hand torque is created on the stator and thereby on the drill string. This torque must be compensated for orienting the tool face, by an amount equal to reactive torque, more towards right which is actually required to achieve desired direction. • Remaining procedure for orientation will be the same as described in orientation procedure with a jetting bit. 213


17.5.4 Trouble Shooting Many common down hole drilling problems can be identified by giving careful attention to mud pressure variation. Table given below gives some information about identification of the problem and corrective measures to be taken which may save costly additional trips. Trouble

Possible Reasons

Actions to be taken

Sudden pressure increase

• Tool Stalls • Internal tool plugging foreign bodies

Pull out and replace tool.

Pressure increasing Slowly above normal

• Bit plugged

Pick up and check pressure. If differential pressure is higher than starting differential pressure; try to clean bit by varying circulation and reciprocate the string. If not successful, pull out. Pick up and check pressure. If drift pressure equals starting drift pressure go ahead.

Change of formation. Slow decrease of pressure

Circulation loss Washout in the drill string

Pull out for check

Decrease in ROP

Formation change

Try with variations in drilling parameters. Change WOB, change circulation

Bit worn

Pull out for bit change.

Tool stalls / NO ROP

Pick up and start again after pressure check, with less WOB.

17.6 BUILD UP ASSEMBLY Near bit stabilizer is used for building angle in build up section. Near bit stabilizer acts as fulcrum which forces the bit up and a reaction force developed on the stabilizer forces the stabilizer to the low side of the hole So while using a near bit stabilizer assembly for kick off a stabilizer with a sleeve having larger blades or integral stabilizer should be used. Following points regarding this assembly should be considered A short Drill Collar is normally added between the bit and the near bit stabilizer. The extension sub gives extra leverage (side force) below the fulcrum point and accentuates the amount of drift angle increase. Note : Higher WOB generally causes an increase in angle build rate and decreasing WOB results a decrease in angle build rate. Rule of Thumb regarding right hand walk In order to slow down the degree of right-hand walk: •

Reduce WOB

•

Increase rotary speed

214


Second stabilizer A second stabilizer is added either 30, 60, or 90 feet above the near bit stabilizer. This stabilizer influences the amount of bend in the drill collars between it and the near bit stabilizer and the bend in the drill collar causes the fulcrum effect. The shorter the distance between these stabilizers, the lesser the bend created between them. The less bend between the stabilizers produces the less fulcrum effect and thereby the less angle will be built. 1. If the distance is 30 feet approximately 0o-0.75o build per 100 feet. It can be used as holding assembly. 2. If the distance is 60 feet, you can expect approximately .25 o-1.25 o build per 100 feet. 3. If the distance is 90 feet, you can expect approximately 1.25o to 2o build per 100 feet. This assembly is also used as angle build assembly. Drill collar stiffness A second method to increase the amount of bend between the near bit stabilizer and the second stabilizer is to change the size of the drill collars. Weight on bit Another way to affect the rate of angle build is by changing weight on bit. An increase in weight on bit when using a build up assembly will, generally, cause an increase in the angle build rate. A decrease in weight on bit will generally, cause decrease in the angle build rate. This occurs because the amount of bend in the drill collar between the near bit and second stabilizer will increase or decrease with an increase or decrease in weight on bit. There are four variables which control the rate of angle builds up of build up assembly. 1. By increasing or decreasing the distance between the near bit stabilizer and the second stabilizer, you can increase or decrease the amount of bend and the amount of angle build. 2. By increasing or decreasing the O.D. of the drill collars, you can decrease or increase the amount of bend and the amount of angle build will change w.r.t. to amount of bend. 3. By increasing or decreasing the amount of weight on bit, you can increase or decrease the amount of bend and the amount of angle build. 4. By increasing the rotary speed the amount of angle build decreases. By decreasing the rotary speed the amount of angle build increases. There are four variables which control the rate of angle build up as given below. 0- 30’ Build Up Assembly EXISTING DRIFT ANGLE

WEIGHT ON BIT

ESTIMATED BUILD RATE /100’

MORE THAN 20o

0-15,000 lbs.

0 o - .5 o

15,000-40,000 lbs.

.5 -.75 o

0-15,000 lbs.

0 o -.25 o

15,000-40,000 lbs.

.25 o -.50 o

LESS THAN 20o

215


0- 60’ Build Up Assembly EXISTING DRIFT ANGLE

WEIGHT ON BIT


MORE THAN 20o

LESS THAN 20o

0-15,000 lbs.

.25 o -.75 o

15,000-40,000 lbs.

.5o -1.25 o

0-15,000 lbs.

.25 o -.50 o

15,000-40,000 lbs.

.50o -1o

17.7 PENDULUM ASSEMBLIES OR DROPPING ASSEMBLIES Angle dropping assemblies are based on the pendulum principle. Pendulum effect results when the near bit stabilizer is removed completely or reduced in size, and the upper stabilizer is retained. The upper stabilizer holds the drill collar off the low side of the hole providing a pendulum point. Gravity acting on the lower drill collars tends to pull them back towards vertical. The bit is forced to the low side of the hole, and the angle of the hole is decreased. Points to be considered regarding pendulum assemblies: • As the distance between the bit and the pendulum point increase, the angle drop rate increases. • As the drill collar thickness increases, the stiffness of the assembly below the pendulum point increases. • As the existing drift angle increases, the angle drop rate increases. • As weight on bit increases, the angle drop rate decreases. • As rotary speed increases, the angle drop rate increases. 90’ Drop Assembly EXISTING DRIFT ANGLE

WEIGHT ON BIT

ESTIMATED RATE /100’

30 o -45 o

0-15,000 lbs. 15,000-30,000 lbs.

2 o -2.5 o 1.25 o – 1.50 o

20 o -30 o

0-15,000 lbs. 15,000-30,000 lbs.

1.25 o – 1.50 o .75 o – 1 o

5 o -20 o

0-15,000 lbs. 15,000-30,000 lbs

.75 o – 1 o .50 o - 0.75 o

0o - 5o

0-15,000 lbs. 15,000-30,000 lbs

0 o - 0.50 o 0o

216


60’ Drop Assembly EXISTING DRIFT ANGLE

WEIGHT ON BIT

ESTIMATED DROP RATE /100’

30 o -45 o

0-15,000 lbs. 15,000-30,000 lbs.

1.25 o 1.00o

20 o -30 o

0-15,000 lbs. 15,000-30,000 lbs.

1.00o 75 o – 1 o

0 o -20 o

0-15,000 lbs. 15,000-20,000 lbs

0.75 o 0.50 o

EXISTING DRIFT ANGLE

WEIGHT ON BIT


20 o -45 o

0-15,000 lbs. 15,000-30,000 lbs.

0.75 o 0.50o

0o -20 o

0-15,000 lbs. 15,000-30,000 lbs.

0.25o 0.125 o

30’ Drop Assembly

Packed hole assemblies are used when it is necessary to keep angle and direction change to a minimum. On most directional wells, packed hole assemblies are used after achieving maximum drift angle to hold inclination. 17.8 RIGHT-HAND WALK AND PACKED HOLE ASSEMBLIES Packed hole assemblies are designed to minimize right-hand walk, however, some degree of right-hand walk may still occur when using packed hole assembly. A commonly accepted method reducing walking tendency is to decrease the weight on bit while increasing the rotary speed. If this does not solve the problem, you can change to a stiffer packed hole assembly, or use larger size drill collars to increase stiffness. An extension sub between near bit stabilizer and the bit in packed hole assemblies induces the tendency to build angle slightly. An increase in rotary speed will slow down the build rate especially if combined with a decrease in weight on bit. Commonly used packed hole assemblies are: 1. 0-10-40-70 assembly. 2. 0-30-60 assembly 17.9 SIDE TRACKING Side tracking is done to: 1. By pass a fish that can not be recovered. 2. Correct the crookedness of a hole. If a well has inadvertently gained angle, especially at shallow depth, it is brought back to vertical with this technique. 217


3. Re-drill a hole if the geophysical data indicate missed geological target during the course of drilling a well 4. Drain hole drilling or multiple hole is also a kind of side tracking operation. Technique of side tracking Place a 50-100 mts. long cement plug. The open end d/pipe assembly should preferably have a diverter pipe. 17.9.1 Slurry Design Sufficient WOC depending upon type of cement & additives should be given before testing the hardness of cement plug. If it does not harden in the given time, give more time or drill out and set another plug. 1. Put about 10 tons of weight on the plug gradually and take off the weight immediately thereafter for testing the hardness of cement . 2. Drill About 2-4 mts. of cement top so as to dress down the cement plug top. The plug is to be drilled uniformly at the rate of 5-6 minutes per meter with 3 ton weight on bit, 50 RPM and moderate pump pressure. Once a sufficiently hard plug top is established, the well is ready for side tracking. Thereafter, drill string assembly is pulled out and kick off assembly lowered. 17.9.2 Time Drilling Side tracking, through an application of directional drilling technique, requires to be initiated by adopting time drilling process. Time drilling implies to drill first five meters of interval in a manner so as to permit bent sub motor assembly to allow cutting of a wedge. For this the procedure is as under: 1. Reciprocate the assembly about 8 to 9 times. This helps in cutting a groove in the high side of hole. 2. Circulate with both pumps for about 15 minutes just about 15 centimeters above kick off point. This will facilitate enlarging the hole right above the KOP which will permit quick take off from the cement plug. 3. Drilling parameters are described below: 1st mts 40-45 minutes 2nd mts. 30-40 minute 3rd mts. 25-30 minutes 4TH mts. Normal time 5TH mts. Normal time WOB, should not exceed 2 Ton. • • •

WOB-1/2-1 TON WOB – 1 ton WOB-1-1/2 TON WOB-1.1/2-2 TON WOB- 1.1/2-2 TON

The time drilling will permit drilling laterally and establishing a shoulder on the side of the hole. A close watch will have to be kept on the cutting at the shale shaker. The cement cuttings should graduate to formation cuttings by the time first 5 mts. is drilled out. If this pinching out of cement cuttings is not observed, next five meters is also to bedrilled with time, otherwise normal drilling is continued hereafter. 218

Cementing Operations

CHAPTER - 18

CEMENTING OPERATIONS 18.1 PRIMARY CEMENTATION The success of cementing operations can be improved significantly by following the standard best practices as detailed below. Major factors requiring detailed attention are: • Slurry design / job planning • Blending of cement and additives in bulk handling plant. • Casing lowering, hook up, pre-job arrangement. • Slurry mixing on location, pumping and job execution • Displacement of cement slurry • Job evaluation 18.1.1 Cement Slurry Design and Planning 1. Gather the data, obtain and assess all the necessary information prior to preparing any cement job design and operation programme. The information should include the following points: • Rig, Well No., Field location • Type of job - casing or liner - conventional or sub-sea operation. • Casing sizes, grades, weights and threads. • Casing depths, deviation, hole size, caliper (if available), drilled depth. • Type of mud to be used, mud parameters and rheology. • Bottom Hole Circulating Temperature (BHCT) & Bottom Hole static Temperature (BHST), expected pore and fracture pressures. • Interested zone intervals with Oil Water Contact (OWC) or Gas Oil Contact (GOC) • Any special well problems (high pressure gas, Lost circulation, salt dome etc.) • Cement rise needed • Any other specific requirement from casing cementation. 2. At job planning stage, the availability of equipment and additives for the job execution should be assessed. 3. Calculate the cementing parameters which include the quantity of cement, total mix water, pump rate, well head and bottom hole pressure during displacement, mixing time, mud displacement volume, surface pressure and other related information. This will assure that well will remain under control during the cementing operation. 4. Design maximum allowable down hole slurry density to prevent fracturing. Slurry density should be at least 1 lb/gal (preferable 2 to 3 lb/gal) heavier than the drilling mud. 5. Determine bottom hole circulating temperature (BHCT) from logs and using API Temperature data. Temperature logged approximately 24 hrs. after the last circulation ceased can be used as BHST for API table. 6. Design fluid loss as under, as per API test a) For preventing Gas Channeling: Less than 50 ml/30mins. b) For Liner Cementing: Less than 100 ml/30mins. c) For casing cementing: Approx. 250 ml/30mins. 7. Design cement slurry or preflush / spacer to be displaced in turbulent flow to obtain minimum 10 mins. contact time at the top of pay zone. Preflush i.e. aqueous solution of dispersant and surfactants are not recommended in high pressure wells. 219


8. Weighted buffers i.e. spacers are to be used in high pressure wells and preferably to be designed for turbulent flow. The best results are obtained if not only the density but also the rheological properties of the spacer fall between those of mud and cement slury. Design the spacer such that it is compatible with both the cement slurry and the drilling mud. 9. If turbulent flow is not possible, then design the job for mud displacement in effective laminar flow using rig pump rate as fast as possible within the limitation of fracture gradient. 10. Use 35% Silica flour (BWOC) at BHST above 230° F (110°C) to prevent strength retrogression of set cement. 11. For normal slurries, control free water separation to 1.4% or less. To prevent gas channeling and in cementing highly inclined wells, zero free water control should be a primary objective. 12. Determine cement slurry thickening time at BHCT and bottom hole pressure. Minimum thickening time should be job time plus one hour thickening time to a consistency of 50 Bc. Excessive slurry thickening time should be avoided. 13. When field slurries are to be batch mixed, while running the thickening time test in lab, before following API test schedules for increasing temperature and pressures, the slurry should be stirred in the consistometer at the surface temperature and atmospheric pressure for the estimated batch mixing and holding time on drill site prior to pumping slurry into the well. 14. Slurry consistency for all normal turbulent flow slurries should be 10 to 20 BC. Since sometimes slurries are mixed heavier in the field, so check consistency in the lab for 1 ppg heavier slurry also. 15. Use the same mixing water, cement and additives in Lab testing that will be used on the wells for the job. If additives are dry blended, a blended cement sample must be collected and tested in the cement test lab before the execution of the job. 16. In the case of certain types of cement jobs, such as long cement column rise or long liners where the static temperature at the top of cement is lower than the BHCT, compressive strength test should be performed at the TOC temperature also to confirm the setting of cement at the cement top. 18. Compressive strength of set cement stone should be: • 500psi for drill out • 2000psi for perforations 19. In case of primary cementing of gas wells with expected high pressure, special chemicals need to be added to cement slurry for effective blockage of gas leakage possibility and the slurry should be tested for its gas tight property in the lab prior to its use in the field. 18.1.2 Blending of Bulk Cement and Additives 1. Cement absorbs moisture from its surroundings and changes its properties. Therefore, cement should be purchased in lot preferably meeting the requirement for 4 months only and stored properly. 2. Cement additives are used with Oil Well cement (API Class ‘G’) in order to get the desired properties of cement slurry as per job requirement. The cement additives are available in dry form or liquid form. Dry chemical powder can be blended with dry cement or can be dissolved in mix water, whereas liquid additives are to be mixed with water only 3. During blending of dry additives with cement, verify weight calculations, quantity and name of each additives going into the cement with design composition. Count the additive sacks and cement sacks for each blend. 220


4. Visually inspect empty tanks prior to transferring blended materials to ensure that they are empty. 5. To ensure proper blending, transfer the blended material at least twice between silos before loading on mobile silos or bulk supply boats for drill site delivery. 6. Conduct fluid loss and thickening time test on samples taken from each container to verify blending. 7. Transfer dry blend to empty tank and back to original tank just prior to slurry mixing. If extra empty tank is not available on site, then fluff or percolate air through each tank from the bottom for 15-20 minutes to redistribute additives. 8. When different blends are used, each blend and tank should be clearly identified. 9. Collect and save sample of each composition for post job analysis if failure occurs. Otherwise, throw away the samples after the job. 10. Check to see that all materials required for job are loaded and identified on the transporting vehicles. Verify that correct chemicals are loaded with correct weight and volume. 18.1.3 Preparation and Hook-up for Cementing A.

Lowering of casing 1. Running in speed of casing should be controlled to prevent fracturing and lost circulation. Casing lowering should be so regulated that the maximum annular velocity caused by the movement of the pipe does not exceed the annular velocity during normal circulation. 2. Landing joint(s) should be spaced out so the cementing head can be installed from the stabbing board or rig floor after casing is landed. 3. Casing centralisation is a critical parameter that must be part of the cementing programme. Placing of Centralisers should be done with the help of cementing software in order to have minimum stand-off 67% for deviated wells and near to 100% for vertical wells. Welding of stop ring on casing and use of welded steel bows should be avoided. Use API approved centralizers. 4. Use scratcher against the permeable formation and 200ft. above and below the pay and water zones in case of casing reciprocation. 5. Use double float protection - a float shoe and a float collar. Check its functioning on surface before make up. Use same type of float collar and float shoe. 6. Put float collar and shoe 2-3 joints apart as depth increases. In case of differential float equipment, check the size of the ball for actuating them properly. 7. Last two casing joints should be lowered at a very slow speed.

B.

Pre-cementation job arrangements 1. After arrival at site, calculate the slurry volume required and displacement volume using actual parameters and also total water requirements including the water needed to flush cementing unit and high pressure lines. 2. Check the mud volume on the site, the hole conditioning, mud rheology, density, flow channel return. 3. Ensure that the supply rates of both mud and water required for the job are sufficient for uninterrupted operation. 4. Verify with the rig-in-charge the displacement rates, pressure to apply when plug lands, and how many barrels (or cubic meters) over the calculated displacement volume will be pumped, if the plug fails to land considering the rig pump efficiency. 221


5. In case the displacement is to be performed by the rig pump, the volumetric efficiency of mud pump, functioning of stroke counter and mud line flow meter should be checked. 6. Conduct a pre hook up meeting to review equipment placement, lay out of high pressure lines, material mixing and pumping sequence, pump rates, slurry densities, safety hazards during pumping operation and maximum allowable pressure. 7. Check the air compressor operation, fluff the cement of silos, prime the pumps and mixers prior to the starting of operation. 8. In case of offshore, one has to ensure the proper working of air dryer. If not the entire pneumatic system comprising of compressor, silos, surge tank and lines may get clogged and free flow of cement will not be there. 9. In case of floater rigs, a mandrel is used for carrying top and bottom plugs. Ensure that this has been serviced immediately after the last use. 10. Check the cementing head, plug release mechanism, plug dropping indicator and review the number and placement of rubber plugs in proper sequence. 11. A detail cementation plan indicating the step by step job sequence duly approved by the concerned well-site incharges should be made and circulated prior to the operation. C.

Cementing equipment 1. Check the cementing units and bunkers to avoid any breakdown during the operations. 2. Check the discharge of each cementing unit physically for their capacity in accordance with the liner size. 3. Check the tanks of cementing unit thoroughly, clean if needed. 4. Pressure test the cementing head and all connecting lines at 1.5 times the maximum pressure expected during the job. 5. Check and calibrate the pressure gauges.

D.

Mud conditioning 1. Begin pipe movement and mud conditioning immediately after the casing is lowered. The casing movement should continue throughout the circulation period. When reciprocating, the pipe is usually moved through a 20ft stroke, using a 2 min. interval for the cycle. For rotation, the pipe is rotated as slowly as possible, usually between 10 and 15 rpm. 2. Adjust Plastic Viscosity (Pv) and Yield Point (Yp) of the mud to the lowest possible values without dropping solids during mud conditioning. 3. Condition hole with good surface conditioned mud at a rate anticipated for cement pumping rate for 1.5 to 2 cycles (minimum). For critical jobs such as production casing cementation fresh mud having low rheology may be pumped ahead of cement slurry. 4. Large percentage of annular open hole (at least 90 to 95%) should be “circulatable”, before the cement job to achieve the best results.

18.1.4 Job Execution A.

Cement slurry mixing and pumping 1. Pressurize bulk units to 15-25psi just prior to starting mixing slurry. 2. Start the pumping operation to break circulation to ensure that the casing shoe is open and check the mud return. 3. Do not premix the cement additives in the water more than 5-6 hrs. before the cementing 222


4.

5. 6.

7.

8.

9.

10.

11.

B.

job. Before premixing additives in water, better to wait until the final circulation is started after casing lowering to the target depth. Verify metering device if liquid additives are pre mixed in water, continue to agitate chemical water thoroughly until the job is complete. The mix water for cement should be measured through displacement tank because it helps to calculate easily how much quantity of cement has been pumped in the event of unplanned shutdown. When liquid cement additives are mixed in displacement tanks, measurement of mixed water is absolutely necessary as tanks are alternately filled and emptied. Control slurry density with pressurized mud cup balance. Check calibration of densometer as well as mud cup balance with fresh water to ensure the reliability of density readings. Use top and bottom cement rubber plugs. Inspect plugs before loading. Turn bottom plug upside down and inspect hollow core and rubber diaphragm. Do not puncture diaphragm of bottom plug prior to loading. Bottom hollow plug is loaded first and then Top solid plug is loaded. Check order of plug loading. A bottom plug is not recommended with large amounts of lost circulation material in the slurry or with badly rusted or scaled casing, as such material may collect on the ruptured diaphragm and bridge the casing. Displace top plug out of cementing head without shutting down operations. Do not open cementing head to drop top plug and better to use a two plug container, as it will allow the well to suck in air and cause honey combing of cement around the shoe joints. Use pre-flush or spacer volume equal to 150-200 m annular height, Pump pre-flush or spacer ahead of bottom plug. Better use two bottom plugs, one ahead of pre-flush and one ahead of cement slurry. Be sure to conduct compatibility test with pre-flush, mud and cement slurry. To ensure good control of slurry density and other properties, batch mix all cement slurries, if possible. Alternatively use continuous mixing devices like Precision Slurry Mixer (PSM) or Recirculating Cement Mixer (RCM). Do not try to get the last few quantity of cement out of the cement bunker or surge tank. This will cause reduction in slurry density and will result in poor slurry at shoe joint and outside bottom joints. Maintain constant density of the last 10-12bbls. (2cu.m) slurry pumped which is very critical.

Displacement 1. Determine displacement rate on the basis of the type of casing string to be cemented. Turbulent flow displacement is usually accepted as being the most efficient techniques for achieving good mud removal. However when turbulence all around the casing cannot achieve mainly due to stand off, pump or fracture gradient limitations, then the maximum permissible/ attainable discharge for high laminar flow is recommended for displacement. 2. Cement displacement rate should be as high as possible but at least 1.3 m/sec and preferably 1.8 m/sec to achieve sufficient zonal isolation with reasonable degree of certainty. 3. Field validated computer programs should be used to calculate the highest possible displacement rate within the constraints imposed by formation strength and surface/down hole equipments limitation. 4. Keep casing pipe in motion to improve mud displacement. Reciprocation should be on a 2 minute cycle over 15-20 ft. intervals. Rotation at 3-10 rpm is satisfactory. 5. Displace top plug out of cementing head with minimum down time. 6. Continue pipe movement until the top cementing plug is bumped or casing tends to become stuck. 223


7. Calculate the anticipated mud return rate throughout the job. 8. Mud return is measured in trip tanks or by other means. High return rate is predicted during the free fall period. Slow return is an indication of lost circulation. 9. To check the fluid return, observe pH change, funnel viscosity and density. 10. Monitor the displacement and bumping of plug. Check the flow back by releasing the pressure. Leave casing open during WOC. A small amount of back flow is expected because of thermal expansion and cement reaction. 11. Even if the rig pump performs the displacement, then also cementing unit must remain completely lined up until plug bumps. The plug hitting must be observed carefully and pressure recorded in cementation job reports. 12. In the event of failure of float valves, the casing should be kept closed at pressure equal to the differential pressure till the cement slurry thickens and rig-in-charge should be cautioned to release the casing pressure by bleeding it off after thickening time of cement to prevent the formation of micro annulus. 13. During cementation a person should be designated to monitor returns from annulus on mud channel. 14. Pressures test the casing for leaks immediately after the top plug bumps in cases where the displacement fluid is water. 15. Do not over displace if the plug has not bumped when calculated displacement volume has been pumped. 16. Maintain log of operations to include operation in progress, time, density measurement, mixing rate, volume of fluid pumped, pumping pressure, displacement rate etc. 17. All specific events occurring throughout a cement job must be recorded along with other relevant points for post job evaluation. C.

Waiting-On-Cement 1. Sufficient WOC time must be observed for the cement to develop adequate strength before operations are resumed. For a period of hours after the plug is bumped, the cement is rigid but has very little strength, and any damage sustained by the cement sheath during this period does not “reheal”. 2. The required period of WOC time varies depending on the cement and down hole condition of temperature and pressure. 3. Cement used to cement an intermediate casing string should have compressive strength of at least 500 psi before drilling is resumed. 4. Completion interval cement should have compressive strength of at least 2000 psi before the well is perforated.

18.1.5 Cement Job Monitoring 1. Use a cementing monitoring van to collect data and to enable job supervisor to observe entire operation. 2. Compare data with calculated predictions and carry out post analysis of the job. 3. Calculate material balance for mix water, cement and cement additives and compare with volume of each slurry pumped. 4. Prepare a summary of the completed job.

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18.1.6 Job Evaluation/ Post Job Analysis 1. Evaluation of cement job is very crucial to determine the success of a cement job for its objectives. A complete post job analysis comparing field job parameters with actual results is the best way to reasonably understand what happened in down hole and accordingly necessary corrective measures for future operation may be applied. 2. Caliper, CBL-VDL, CET or USIT logs can provide accurate and useful information to evaluate post job success or failure. However, production results are the actual proof of the acceptable quality of cementation. 3. The general rule is that the cement bond log should not be run until 48 hrs. after the cementation in order to achieve the true cement bond reading. This again is highly dependent on the cement type and additives used in the slurry and bottom hole conditions. 4. Field results show that more than 90% of wells exhibit a micro-annulus on a primary cement job. Always record CBL-VDL under 700-1000psi pressure to eliminate micro-annulus effect. 5. The bond index method is most commonly used for interpretation of amplitude curve in CBLVDL towards achievement of zonal isolation. This method is essentially a graphical solution, which allows determination of amplitude value corresponding to a particular bond index. One of the guidelines followed by international operators for deciding on requirement of remedial jobs based on the bond index method given below. Guide lines of APIT (alliance process improvement team) - SPE - 52810 5" Casing - 5 feet of 60% bond 5-1/2" Casing - 6 feet of 60% bond 7" Casing - 10 feet of 60% bond 9-5/8" Casing - 12 feet of 60% bond These guidelines promote a “lean forward” approach and reduced number of squeezes resulting in reduced completion cost, less rig time and elimination of complication results from squeezes 18.2 SPECIALIZED PRIMARY CEMENTING OPERATIONS 18.2.1 Multistage Cementing It is the conventional placement of cement slurry around the lower portion of the casing string followed by placement of successive upper stage through ports of stage collar. Most stage cementing is in two stages, although additional stages are possible. 1. Design cement slurry for the first stage and second stage at temperature and pressure at the casing depth and stage collar depth respectively. 2. Check before the stage cementing collar is made up on the casing the size of the trip plug/ freefall plug/opening bomb, I.D of the opening sleeve and closing sleeve and the size of the seats provided in opening & closing sleeves. 3. Regardless of the type used, caution must be exercised in the initial handling of the stage collars, as the equipment is manufactured to close tolerances. Smooth sliding and sealing of the concentric sleeves is necessary for proper operation. Rough handling prior to or during installation can “egg” or misalign the moving parts, causing a failure during job execution. 4. One must also be absolutely sure that the float collar and the stage collar are compatible. The first-stage wiper plug (if used) and the first-stage displacement plug must fit and seal against the float collar. 225


5. Run in the casing with the stage collar at the desired depth. Stage collar should be tightened by putting the tong at the designated place on the outer sleeve of the stage collar only. 6. The stage collar should preferably be placed against the shale section. 7. Besides slurry pumping displacement and safety factor, the first stage slurry thickening time should include the traveling time of bomb, opening of ports and one cycle circulation through stage collar ports. 8. One centraliser may be placed just above the stage collar and one below the stage collar. 9. After completion of first stage cementation job, drop the opening plug or bomb and allow it to reach the stage collar. Opening plug velocity is approx 1m/sec in normal mud. Ensure the seating of freefall plug for opening of stage collar port. To open the ports slowly build-up pressure usually approx. 1,200 to 1500 psi. A drop in pressure will indicate that fluid has escaped into the annulus after opening of ports. 10. Circulate the well through the stage collar ports for 2 cycles to flush out any extra / contaminated cement from the first stage and the well must be circulated untill the mud is conditioned for the second stage. 11. Release closing / shut off plug in such a manner so as to have some cement slurry over it. This will ensure cement outside the stage collar and minimize the hazards of displacement fluid outside the stage collar. Further cement above shut off plug will help in drilling it out. 12. For closing the cementing ports approximately 1500psi pressure in excess of second stage final / cementing pressure is to be built up over the shut off plug in one continuous operation without slowing down or stopping the pumps. Confirm the closure by bleeding back. 18.2.2 Stab in Cementing Stab in cementing is done when large size of casing necessitates high displacement volume in conventional cementing or combined strings do not allow the use of conventional plug. This cementing is carried out with drill pipe with a stabbing unit attached to its bottom end. The drill pipe with stab in unit (stringer) is stabbed into the stab-in cementing collar or shoe and then cementation is carried out. 1. Run in the casing in place with a stab-in float shoe/collar and set in the casing slips suspending the string off bottom. 2. With the casing set, fix the stringer equipped with a centraliser at the end of drill pipe string and run in the assembly until it is approximately 3 ft (1 m) above the float shoe/collar. When running in, the pipes are filled with the same fluid as the one placed in the well. 3. Establish circulation with the drilling fluid and see the returns coming from the annulus between the drill pipe and the casing. 4. Stop circulation and lower drill pipe so as to enabling the stinger to stab into and seal in the stab-in float shoe/collar in the casing. As much as possible, the stringer is engaged only once into the collar or shoe. Test the surface lines and hermeticity of the inner string. 5. Again establish circulation and observed for returns flowing between the conductor pipe and the casing. 6. Mixed cement and pumped through the drill pipe and up the annulus until it reaches the surface. As soon as mud contamination is no longer evident in the cement returns, mixing can be stopped and the drill pipe volume displaced. Continuously monitor the weight on string during displacement to ensure proper engagement of stringer all the time 7. If lost circulation is noticed before the cement reaches the surface, mixing should be stopped and the cement displaced, avoiding the pumping of large quantities of cement into the 226


fractured zone. Care must be taken to avoid collapsing the casing because of excessive differential pressure between the outer annulus and the drill pipe/casing annular space. 18.2.3 Liner Cementation A liner is a standard casing string which does not extend all the way to the surface up to the well mouth, but it is hung from inside the previous casing, generally keeping an overlap of 50 to 100 m A. •

• •

•

• • • • •

•

Critical points for liner cementation Slurry Design: While designing the cement slurry for liner cementation job, the following slurry parameters should be carefully considered. Thickening Time: It is usually designed to include the time taken for reversing out the excess slurry above the liner hanger top. However the wells where high pressure gas is being isolated behind the liner, relatively short thickening and setting time are required to reduce chances of gas penetrating the unset cement. Slurry Density: High density low water ratio cement is used to prevent water separation and entry of fluid into the well bore, but the combined density and displacement pressure must remain below the fracture pressure of the weakest zone. Fluid Loss Control: Fluid loss of the slurry should remain less than 100 ml/30mins so as to avoid building up of cement filter cake and to reduce chances of annulus bridging due to small annular channels. A four arm caliper should be run prior to the liner operation to ascertain the hole size for calculation of cement slurry volume which is very critical for liner cementation. No lost circulation material should be used in liner cementation to avoid plugging of float equipment or the narrow annulus. If loss control material is added in mud to combat loss, then after lowering of liner the well should be circulated with fresh mud free from LCM (Lost Circulation Material). Centralising the liner in the hole is very critical, because annular clearance are so small that the liner must be kept clear of borehole wall for effective cement placement. This is particularly true in case of deviated wells. Bow spring centralizers may be used in the open hole if there is sufficient annular clearance. Rigid centralizers are used in the casing/liner lap region, and also in the open hole in cases of very narrow annular clearance. Centralizers or positive stand off devices also reduce the likely hood of differential pressure sticking of the liner in the open hole. The length of the liner overlap can be as little as 50ft for a drilling liner or as much as 500 ft for a production liner. In deviated wells rotating type liner is recommended to facilitate mud removal and placement of cement slurry at the lower side of the hole. Use combination dart in case of combination string is used for lowering liner. Preferably use liner hanger with integral packer or with top seal in case of loss prone areas to avoid hanger top squeeze job. The small clearance also makes it difficult to run liners. Swab/ surge pressure can be extremely severe and running speed should be slow to avoid pressure that could break down formations to cause lost circulation. It is frequently necessary to restrict running speed to one stand of drill pipe every 2 – 3 min. Circulation should be carried out before setting the liner to clean the mud system of any cutting or debris. Cutting will come during circulation and at the restricted area of liner hanger it may accumulates causing the rise in pressure.

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• •

• • • •

• •

The plug arrangement for liner cementing eliminates the opportunities to run a bottom plug a head of the cement. Normally a spacer fluid which is compatible with mud and cement is pump between mud and cement to provide a buffer to avoid serious contamination. The amount of cement excess for liner cementing must be carefully calculated by taking into accounts the well conditions and displacement efficiency. Displacement efficiency is a key variable in determining cement slurry volumes as it is not uncommon to have 60% to 80% displacement efficiency in liner cementing. Excess volume increase the likelihood for good cement placement but it is also increases the possibility of operating problems. The volume of cement used on most deep liners is usually rather small. Since slurry design parameters are critical for liner cementation batch mixing should be done to promote uniformity. Slow down displacement when the pump down plug (dart) approaches the liner wiper plug in order to observe the first pressure surge (about 300psi) corresponding to the shearing of the pins. Release the liner setting tool after completion of displacement and if packer type liner hanger is used then set the packer. Pull the setting tool free from the liner and reverse out any excess cement above the liner top. If no packer is incorporated into the liner hanger then reverse out keeping excess cement over the top of the liner so that 8 to 10 joints of the intermediate casing will contain cement to be drilled out after setting. Reverse circulation places an extra pressure on the annulus and this additional pressure should be pre-calculated and controlled where necessary to avoid formation break down. A liner packer keeps reverse circulation pressure off the formation. In long liners, there may be a considerable temperature differential between the bottom and top of the liner. The cement may take very long time to set at the top and as such drilling of cement must be done after the cement develop the minimum compressive strength at the top of liner also.

B.

Testing of liner top A leaking liner top can become a serious and expensive problem during future drilling operations, or during the production life of the well. Therefore, testing the top of a liner after it has been cemented is absolutely essential to the success of the well completion. There are two methods that may be used to test the pressure integrity of a cemented liner top. i)

Hydrostatic testing Testing the liner top with applied pressure can be done with or without a packer; however, in either case, burst limitation of the intermediate casing must be considered. In case of a drilling liner, pressure applied to the liner top should be equal to or greater than the hydrostatic pressure at the liner top when the maximum anticipated mud weight has been attained in subsequent drilling operations. To complete the testing of the pressure integrity of a liner top, the fracture gradient of the zone at the shoe of the intermediate casing must also be considered. Until the testing pressure is high enough to be above the fracturing pressure of the zone, the cement job on the liner top has not been tested. ii)

Differential testing A Negative pressure test should be run on liner tops because of the possibility of mud solids plugging up a small channel or the existence of “honeycombed” cement or micro-annulus. These type environment often can not be pumped into and give a false sense of security. A negative pressure test should be equal to any differential pressure that the well may encounter later in drilling or completion. 228


Differential testing of a liner top requires the use of a packer normally set at 100 to 300 ft above the top of the liner. This testing is accomplished by lowering the pressure above the liner to a point lower than the highest pore pressure behind the liner. This may even require partial evacuation of the fluid from the drill pipe by adding nitrogen or some combination of nitrogen and fluid to lighten the column. Differential pressure testing requires close scrutiny of the collapse rating of the liner itself. 18.3 SECONDARY CEMENTATION Secondary cementation jobs are mainly classified as • Plug Cementing • Squeeze Cementing. 18.3.1 Plug Cementation A cement plug of a specified length when placed across a selected interval in an open hole or a cased hole, is called “Plug cementing”. The most commonly used technique for plug placement is known as “Balanced Plug Method”. Plug failures can be prevented by following the standard best practices as detailed below. • Select gauge section of a hole. Consult a caliper log for selecting a location to set a plug and determining the temperature of the formation where the plug is to be set. • Circulate long enough to condition the well so as to ensure that the entire mud system is uniformly weighted. • Check the mud system carefully for loss of returns, fluid gain or gas entry. Any movement of the plug after it is placed may cause the cement not to set. • A cement plug is best set in a competent hard rock. Shale should be avoided as they are often caved and out of gauge. • However, if the kicking off is the objectives, the plug should not be set in a excessively hard formation. Ideally, the plug should extend from a soft shale down to a hard formation. Logs and drilling rate record should be consulted when selecting a location to set a plug for kickoff. • Slurry design Viscous slurries with high gel strength and low density are needed for lost circulation plugs, to restrict flow into voids or fractures. High compressive strength is mandatory in whipstock plug to have a sharp contrast between the plug and the formation hardness. Use densified cement slurry that will tolerate considerable mud contamination. Addition of sand or weighting materials will not improve the compressive strength of lower water content slurry. • Carefully calculate cement, water and displacement volumes and always plan to use more than enough cement (1.5 to 2 times the calculated volume) to compensate for contamination effect so as to get the desired plug length. • Batch mix the cement slurry to ensure uniform slurry density. • Pump preflush that is compatible with drilling fluid. Preflush volume should be sufficient to cover an annular height of 500 to 800ft and the after flush volume should cover the same height in the tubing string as that of the preflush. • For open hole cement plugs in gas wells, use a weighted spacer 1 to 2ppg heavier than the mud. Using water as preflush can cause reduction of hydrostatic head, resulting in gas migration through the cement. • Whenever possible preflush/spacer should be pumped in turbulent flow conditions. 229


• • • • • • •

Try to rotate or reciprocate drill pipe slowly till the completion of displacement. Under displace the plug by 200-300 liters to avoid any back flow. Pull out the drill pipe/tubing slowly (30-50 ft/min) out of the cement to minimize contamination. Reverse wash twice the drill string volume to wash excess slurry out of the hole. Ample WOC time to be allocated (12 to 24 hours) for a plug job. A common practice is to allow for longer WOC time since well temperature for a cement plug job is difficult to know accurately. Always test the cement plug by tagging top of cement with Bit and apply required weight for “Hardness” test. While placing a cement plug for kick-off special measures as depicted below are required to be followed for success at first attempt Use either a mechanical or chemical method to provide some static barrier below the intended bottom of the plug When a high viscous pill is used for achieving a static barrier below the cement column, then the length of the pill should be equal to the cement plug length and funnel viscosity of the pill should exceeds 150 sec. Also the pill density should be greater than the mud weight and 10 sec gel strength of the pill should be above 50 lbs/100 sq.ft. Use a “Divertor tool” for placement of cement to achieve uniform placement of cement slurry all around the wellbore and to prevent contamination due to downward movement. Typically 2 7/8 tubing should be used as tail pipe to minimize contamination during pulling out as it will create less disturbances of the cement plug when the pipe is being pulled. The length of tail pipe should be 1.5 - 2 times the plug length. At least provide 48 hrs. W.O.C for attaining sufficient hardness/ strength for sidetrack plug.

18.3.2 Squeeze Cementing Squeeze cementing is defined as the process of forcing cement slurry, under pressure, through holes or splits in the casing/well bore annular space and then allowing it to dehydrate by further application of pressure. Squeeze cementing is necessary for many reasons but probably the more important use is to segregate hydrocarbon producing zones from those formations producing other fluids. The key element of a squeeze cementing job is that of placement of cement at the desired point or points necessary to accomplish the purpose. A basic fundamental of squeeze cementing is that regardless of the technique used during a squeeze job, the cement slurry (a suspension of solids) is subject to a differential pressure against a filter of permeable rock. The resulting physical phenomena are filtration, filter-cake deposition and, in some cases, fracturing of the formation. The slurry, subject to a differential pressure, loses part of its water to the porous medium, and a cake of partially dehydrated cement is formed. As the filter cake builds, the pump in pressure increase until a squeeze pressure less than fracturing pressure is attained. A good guide for a squeeze pressure is 500-1000 psi above the pump in pressure with no flow back in 3 to 5 minutes. A.

INJECTIVITY TEST PRIOR TO SQUEEZING Prior to placement of cement slurry, conduct injectivity test against the squeeze interval to determine if and at what rate below the fracture gradient fluid can be placed against the formation. A rate sufficient to allow adequate time for cement placement must be reached before actually 230


mixing the cement. When the fracture gradient must be exceeded to obtain sufficient rate for cement placement, it should be done without excess. A minimum of ten barrels volumes should be used when obtaining an injection rate. Deep perforations require more volume than shallow ones because of the additional hole volumes. Consider spotting a clear fluid such as water across the perforations when obtaining an injection rate. The injection test is performed for several reasons: • To ensure that the perforations are open and ready to accept fluids. • To obtain an estimate of the proper cement slurry injection rate. • To estimate the pressure at which the squeeze job will be performed, and • To estimate the amount of slurry to be used. If suitable injection rate could not be established at the desired injection pressure, it may be necessary to use acid to clean up the perforations, channel etc. Hydrochloric and hydrofluoric acids are commonly used. While taking injectivity test, raise the pressure very slowly up to the point of injection without fracturing the exposed formation. B.

Design of Cement Slurry for Squeeze Job The properties of cement slurry must be tailored according to the characteristics of the formation to be squeezed, and the technique to be used. Squeeze slurry should be designed to have the following general attributes: • Low viscosity: to allow the slurry to penetrate the small voids • Low gel strength: a gelling system restricts slurry movement • No free water • Appropriate fluid loss control. Proper thickening time: to safely meet the anticipated job time. Following factors may be considered in designing the cement slurry for any squeeze operation: i) Fluid Loss Control Fluid loss and filter cake growth rate vary directly i.e. higher the fluid loss, faster will be the filter cake build up. As such, while designing the slurry, fluid loss must be tailored to the formation type and the permeability so as to achieve a uniform cake build up against the squeeze interval. The generally accepted API fluid loss rates are listed below: Extremely low permeability formation - 200 ml/30min Low permeability formation - 100 to 200ml/30min High permeability formation (>100md) - 35 to 100 ml/30min ii) Thickening Time The temperatures encountered in squeezing can be higher than those of primary jobs, because fluid circulation before the job is usually less. For this reason, special API testing schedules exist for squeeze cement slurry design and must be followed to prevent premature setting. The added stringency in the API testing schedules for squeeze cementing simulates the actual temperature the slurry is subjected to when hold near bottom for extended periods. Thickening time must be sufficient to assure slurry placement and reversing out of the excess. For running squeeze method, requirement of thickening time should be less. 231


Whereas for a hesitation squeeze method, higher pumping time must be designed so that cement slurry remains in fluid stage till squeeze pressure is achieved. iii) Compressive Strength High compressive strength although desirable but is not a primary concern for squeeze slurry design as a partially dehydrated cement cake of any normal cement slurry will develop sufficient compressive strength. C.

Slurry Volume The optimum amount of cement is the volume required to seal the void. The volume of slurry needed is generally inversely proportional to the injection pressure and directly proportional to the injection rate. The appropriate volume of cement slurry depends upon the length of the interval to be cemented, and the placement technique to be used. A low-pressure squeeze requires only enough slurry to build a certain filter cake in each perforation tunnel. In many cases less than a barrel is sufficient. However, for job convenience and because of problems in placing the cement into the correct place to provide a seal, a 5-15bbl batch is normally prepared. A high-pressure squeeze, in which the formation is fractured, requires a higher volume of slurry. The following may be considered when determining the volume of cement to use. • The volume should not exceed the capacity of the running string. • Two sacks of cement should be used per foot of perforated intervals restricted to a minimum of 50-sacks. • The minimum volume should be 100 sacks if an injection rate of 2bbl/min can be achieved after breakdown: otherwise it should be 50 sacks. • The volume should not be so great as to form a column that cannot be reversed out. • The volume of the void to be filled behind the cement or in the zone plus the volume to be left in casing but not less than 50 sacks.

D.

Squeeze Pressure Squeeze pressure is the pressure at the injection point. In most cases, if the cement can be placed at the proper point, a successful squeeze can be obtained with 500 to 1000 psi standing pressure above the injection pressure. The pressure should be hold for 10 to 15 minutes with no flow back. Low-pressure squeeze is recommended where possible. A safety factor of about 300 psi below formation fracturing pressure is reasonable for low pressure squeezing. After a squeeze is obtained, the pressure should be bled off and the volume of fluid measured. The squeeze should then be repressured and the volume measured again. If the volumes are equal, this indicates that the squeeze has held and the volume of fluid pumped compensated for tubular expansion.

E.

Lurry Preparation When preparing the slurry, the use of a recirculating mixer or batch mixer is strongly recommended, because it ensures that the properties of the slurry pumped in the well are as close as possible to those of the slurry designed in the laboratory. On most squeeze jobs, the amount of slurry involved is quite small, but the requirements of its quality are quite high, therefore special care must be taken in preparing it.

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F.

Evaluation of Squeeze Job Pressure testing is the most common means of evaluating the success of the operation. Both positive and negative test should be used. A squeeze job may appear successful when pressure is applied to the well bore but may fail to hold back the pressure from the zone into the casing. The universally recognized technique for confirming whether the cement in place will hold the formation fluids under producing conditions consist of applying a negative differential pressure on the face of the plugged perforations. Positive pressure test After the W.O.C time, test the cement by applying required surface pressure for checking integrity of the perforation squeezed. The pressure applied at the face of the perforation is predetermined at the job design stage. It may be the reservoir pressure or pressure equal to future working pressure in the well from fracturing or acidizing treatments but should not exceed the formation fracturing pressure. Negative pressure test A negative test or differential pressure testing of the well bore may be obtained either by swabbing and lowering the fluid level or by displacing work over fluid with some lighter fluid. Negative pressure test should be conducted using pressure no greater than the expected maximum drawdown in the well when it is put into production. When the objective of the squeeze is to repair a primary cement job, the normal cement log (CBL/VDL) should be run to evaluate the effectiveness of the repair by comparing pre-squeeze and post squeeze logs.

G.

Misconception in Squeeze Cementing •

The cement slurry penetrates the pores of the rock Only the mix-water and dissolved substances penetrate the pores, while the solids accumulate at the formation face and form the filter cake. It would require a permeability higher than 100 darcies for the cement grains to penetrate a sandstone matrix. The only way for slurry to penetrate a formation is through fractures and large holes.

•

High pressure is needed to obtain a good squeeze If the formation fracturing pressure is exceeded, control of the placement of the slurry is lost, and the slurry enters unwanted areas. Pressure is of no help to place the slurry in all the desired location. Once created, a fracture may extend across various zones, and open unwanted channels of communications between previously isolated zones.

•

Plugged perforation It is rare to find all perforations open and producing. Perforations will usually have some degree of mud fill up, depending on the completion, fluid. Mud filter cake is capable of withstanding high pressure differentials especially in the direction from the well bore to the formation and the high pressures may create a fracture before accepting cement filtrate. Many squeeze failure may be attributed to subsequent clean up of a previously plugged perforation which did not accept the cement slurry during the squeeze job.

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H.

Squeeze Cementing Procedure a) Low Pressure Squeeze Cementing 1. Consult a CBL / VDL log prior to squeeze job. 2. Decide the point of perforation and perforate against a permeable formation at least 6 to 8 Shots (Gun Perforation) per foot for achieving better intake. 3. Carry out injectivity test in water. If injectivity is found to be poor, acid job may be required to improve injectivity. 4. For low pressure squeeze cementing, follow all the standards as given for a normal cement plug job so as to spot the slurry against the perforated interval. 5. Then pull out drill string sufficiently above the cement top. 6. Close BOP and apply pressure through drill string to squeeze cement. 7. Squeeze calculated volume of slurry and close the well under pressure for 4 hrs. b) Block Squeeze Cementing 1. For block squeeze perforate 2 sets of perforation i.e. above and below the cement retainer. 2. If the poor bondage is continuous for a longer section, decide to carry out block squeeze using a cement retainer. 3. Establish circulation through cement retainer behind casing with water or cleaned fluid to ensure good clean up of the channels. 4. Maintain the down hole treating pressure below the formation fracture pressure when carrying out injectivity test or establishing circulation behind casing. 5. Calculate slurry volume keeping into consideration the annular volume and slurry required below cement retainer. 6. Use spacers ahead and behind cement slurry for a minimum length of 50 to 75m to avoid contamination. 7. While displacement monitor free falling /U tubing of cement slurry by controlling through choke. Displace cement up to the tip of cement retainer so as to keep the cement inside the string and engage tubing string to retainer, and squeeze to circulate out cement between the two perforations. 8. Disengage the string from retainer and balance the plug. Pull out the string above the top of perforations, reverse wash and squeeze cement in the upper perforation (optional) and keep the well under final squeeze pressure. c) Water /Gas Shut Off Squeeze 1. For elimination of water intrusion or reduction of gas oil ratio this squeeze cementing is carried out to seal all the perforations and then re-perforate a selected interval. 2. All procedures that of low pressure squeeze cementing are to be followed for placement of cement slurry against the perforated interval. 3. In case of good injectivity, squeeze calculated volume of slurry into the perforations leaving a cement plug inside the casing. Squeezing to be done by hesitation method, so that final squeeze pressure is achieved. 4. In case of no injectivity, squeeze cement slurry at the maximum permissible squeezing pressure and close the well under squeeze pressure for 4 hours.

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18.4 HANDLING AND STORAGE OF CEMENT AND ITS ADDITIVES 18.4.1 Handling a) Care must be taken during handling and transportation of cement/ additive bags so as not to allow introduction of moisture. b) Use of iron hooks be avoided as it will puncture the bags and expose the material to moisture. c) Possible contamination of bulk cement by other cement brands or bulk materials should be avoided in offshore operations. d) Suitable moisture scrubbing equipment should be added in the cooler air lines between compressor and tanks. Particular care should be taken in offshore bulk cement handling operations to avoid transfer lines becoming wet. e) One type of cement additive should be kept together. f) For offshore use, cement additive should be sent to installation in sealed containers and if sent on pallets, then it should be properly covered with water-proof tarpaulin. 18.4.2 Storage a) Cement chemicals should be kept separately from other chemicals to avoid any intermixing of bags. b) Storage of cement / chemicals should be such that oldest stock will be issued first. c) It is advisable to store cement chemical bags on a platform with approximately 6 inches air space and tarpaulin should be spread on the base of stacking in order to form a moisture proof seal. d) When stored on pallets, cement and additives should be stored from initial stage of receipt of material and on a pallet not more than 20 bags of additives and 30 bags of cement should be placed. e) While storing cement for a long time in silo, either on site or in bulk handling plants, cement should be transferred from one silo to another, at least once in a month. f) Air dryer must be used for moisture free air in handling cement when storing in silos. g) Staggered delivery schedule should be maintained. 18.5 CHECKLIST FOR CEMENTATION JOB 18.5.1 Before Casing Running In 1. Tally the casing and total depth such that the casing can be landed within 1.5 m (5 ft.) of the bottom (floor). 2. Caliper log should be recorded to know the hole size at various depths and for the calculation of cement slurry volume to be pumped to achieve desired cement rise. 3. Well is properly conditioned so that it is free from lost circulation, tight pull, caving and activity prior to pulling out for casing lowering. 18.5.2 During Casing Running In 1. Check the prepared casing running and fill up schedule. 2. Control lowering speed to prevent fracturing/loss circulation. 3. Control torque make up on casing threads. 4. Use differential type of floating equipment in potential mud loss wells.

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5. To see that float shoe is checked and placed on first joint of casing to guide casing into well and minimising derrick strain. 6. To check float collar and should be placed on one/two/three joints above casing shoe depending upon well depth. 7. To ensure float shoe and float collars used are of same type. 8. Type of floating equipment, conventional or differential. If differential type is used, the tripping ball is checked. 18.5.3 Mechnical Aids 1. To check the following for centralizers : i) Total number of centralisers used. ii) Ensure use of stop rings to place the centralizers. iii) Ensure the stop rings are not welded on casings. iv) Ensure centralizer spacing done with computer programme. v) 60 Mts. below and above the zone and the interval of the zone should be properly centralized. vi) Total cement column is centralized. 2. Ensure use of scratchers against permeable formation to remove filter cake 3. Ensure use of swirlers in washout sections. 18.5.4 Circulation Prior to Cementation 1. Condition hole with good surface conditioned mud at a maximum possible rate within the limitation of fracture gradient for 1.5 to 2 cycles (minimum). 2. Circulation rate and pressure. 3. Mud was conditioned to lowest possible Pv & Yp as the system permits without dropping solids. 4. Mud parameters during final circulation: i) Specific gravity. ii) Pv iii) Gel vi) Viscosity v) water loss 5. Casing reciprocation during circulation was done. 6. Cementation started only after the mud is free from any gas bubbles /pockets/ cuttings and at least 90% of the hole mud is being circulated. 18.5.5 Cementing Head 1. Whether single or double plug container cementing head is used. 2. Cementing head should be checked for any leakage during cementing operation and proper function of plug release indicator. 3. Stopper pin is checked for its easy movement. 4. Top and bottom plugs are placed in proper sequence viz. Bottom hollow plug is loaded first and then top solid plug.

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18.5.6 Cementing Equipment 1. The cementing units, bunkers/silos are thoroughly checked to avoid any break down during the operations. 2. The discharge of cementing unit is checked physically for their capacity in accordance with the liner size. 3. Tanks of cementing units are thoroughly cleaned. 4. Cementing head and all connection lines are pressure tested to 1.5 times the max. pressure to be encountered during cementing. 5. Check and calibrate the pressure gauges. 18.5.7 Blending of Cement Additives 1. A minimum of two transfers of cement and additives is a must, when dry blending is recommended. 2. Correct weights (dosage) of powdered additives are mixed. 3. Conduct test of each blended cement sample. 4. If wet mixing is done, the correct percentage of additive is thoroughly mixed with the mixing water. 18.5.8 Preflush / Spacer 1. Check whether sufficient volume of Spacer/Preflush to be displaced ahead of cement slurry in turbulent flow with minimum 10 minutes contact time or equal to 150-200 mts. of annulus height, is prepared. 2. Check compatibility of preflush/spacer, drilling mud and cement slurry at room temperature and BHCT. 18.5.9 Cement Slurry Design 1. Determine maximum permissible down hole cement slurry density to prevent fracturing or induced losses. The density of cement slurry should be at least 1 ppg (preferable 2-3 ppg) heavier than the drilling mud. 2. Correct bottom hole circulating temperature and pressures should be used to design the slurry. 3. Thickening time: a. Is there a safety factor for placement taken into consideration? b. Has it been laboratory tested with drill site technical water under simulated conditions? 4. Viscosity (Consistency) of cement slurry is low enough for the required displacement rate to achieve turbulence. 5. Fluid loss control is adequate as per well requirement. 6. Free water is controlled as per well requirement. 7. Comprehensive strength of cement is determined after 24 hrs. and 48 hrs. at BHST. 8. Silica Flour 35% is used with ‘G’ class cement at temp. above 110°C. 18.5.10 Slurry Mixing and Pumping 1. Sufficient mixing water is available for the volume of cement to be mixed and enough liquid or solid additives are present at site. 2. Mixing pump pressure should be tested for required discharge.

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3. Batch mixer/ recirculating mixer/ precision slurry mixer is used for preparing homogenous slurry. 4. Mud balance or other density measuring device is calibrated with fresh water before actual cement job. 5. The sp.gravity of cement slurry is continuously monitored during cementation job. 6. The sp.gravity of cement slurry is maintained as close as the lab design with variation of ± 0.2 ppg. 7. Quantity of cement used and slurry volume pumped is as per plan. 8. Continuous monitoring of mud returns during cement slurry pumping. 18.5.11 During Displacement 1. Displacement volume is calculated as per casing string actually being run in the well. 2. Displacement is to be done by a) Rig pumps b) Cementing units. 3. Number of strokes were calculated with 100%, 98% or 95% rig pump efficiency. 4. The discharge of the rig pump is checked physically as well as theoretically. 5. The SPM of pump was calculated to achieve desired flow regime during displacement. 6. Casing was reciprocated/ rotated during cementing operation. 7. Cycle of reciprocation ——————m/mins. 8. If rotated, the speed of rotation—————RPM. 9. Displace top plug out of cementing head with minimum down time. 10. Last 200 strokes are pumped at slower speed to bump the plug. 11. Check function of NRVs. 12. Pressure applied to be calculated in case of NRV failure. 13. If well was kept under pressure, necessary directions to be conveyed to shift in-charge for monitoring of pressure during WOC. 14. Casing left open during WOC if NRV holds after plug hitting. 15. Continuous monitoring of mud returns during displacement. 18.5.12 1. 2. 3. 4. 5. 6. 7. 8.

Operational Considerations Necessary instructions to be passed to the cementing officials before starting the job. The cementing unit pumps are loaded prior to starting the cementation job. Extra bunker / silo loaded with cement is kept as standby Necessary arrangement for applying back pressure (if it is to be given) has been made. Anchoring / rig up of cementing units has been properly made. Supply of water to the cementing unit has been checked. Safety precaution has been taken prior to commencing of actual cementing operation. WOC time specified is sufficient.

18.5.13 Monitoring 1. Data comparisons with calculated predictions and post analysis of the job. 2. Calculate material balance for mix water, cement and cement additives and compare with volume of each slurry pumped. 3. Prepare a summary of the completed job.

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18.5.14 1. 2. 3. 4. 5.

Evaluation Quality of CBL/VDL: Excellent / Satisfactory / Poor. CBL/VDL was taken after 48 hrs. / 60 hrs. Whether CBL/VDL is recorded under pressurized conditions. CBL/VDL taken before or after hermatical test. Interpretation of CBL/VDL in terms of Bond Index.

18.6 WELL ABANDONMENT PROCEDURE Well abandoning procedures shall be different between onshore and offshore. 18.6.1 Onshore Well Abandonment Any oil gas or fresh water show should be isolated with cement. If a caliper log is available, correct volume of cement should be calculated and placed to cover the predetermined length of cement plug. The bore hole including the space between the cement plugs shall be filled with drilling fluid of sufficient specific gravity and other properties so as to enable it to withstand any subsequent pressure which may develop in the bore hole. 18.6.1.1 Open Hole Abandonment I. Isolation plug: Where there is open hole below the casing, place a cement plug of 50m in open hole and 50m inside the casing shoe. II. Tag and test the plug prior to placing subsequent plugs. III. Surface plug: Place a surface cement plug of 100m inside the casing between a depth of 200 to 300m. 18.6.1.2 Cased Hole Abandonment I. A hydrocarbon producing zones should be isolated by cement squeezing and plugging. II. Last object tested, should be squeezed with cement and leave a cement plug of minimum 150 m above the zone of interest. Tag the top of plug and test it to 500psi pressure. III. Plugging of casing stub: If the casing is cut and recovered there by leaving a stub inside the next larger string, abandonment cement plug should be set so as to extend a minimum of 50m above and 50 m below the stub. IV. Surface Plug: A cement plug of at least 100m with the top of the plug 100 to 200m below the surface should be placed in the string. 18.6.2 Offshore Well Abandonment Procedures 18.6.2.1 Isolating Perforated Interval To abandon a zone, a cement plug should be placed opposite all open perforations extending a minimum of 30m above and 30m below the perforated interval by the balance cement plug /squeeze method. A permanent type bridge plug may be set within casing above the top of the cement plug up to the maximum possible depth run without scrapper trip. If the perforations are isolated from the hole below, squeeze cementing operations should be accomplished using the Braden head method or a cement retainer.

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18.6.2.2 Plugging of Casing Stubs Abandonment may be accomplished by one of the following methods if the casing is cut and recovered thereby leaving a stub inside the next larger string. 1. A balanced cement plug should be set so as to extend approximately 30m above and 30m below the stub. 2. A permanent bridge plug may be set at least 15m above the stub with a minimum of 50mts. of cement plug on top. 3. In uncased open hole of well, a cement plug should be placed by displacement method so as to extend at least 30 to 50mts. in open hole below the casing shoe and a minimum of 50mts. approximately cement plug should be placed inside the casing. 4. If loss circulation exists or is anticipated, a permanent type bridge plug may be set within 30-45 mts. above the casing shoe. This bridge plug should be tested prior to placing a subsequent cement plug of minimum 50m above it. 18.6.2.3 Surface Plug Requirement After abandoned plug and squeeze in the last object, set a bridge plug in casing at maximum possible depth without scrapper run. Check 20″ x 13.3/8″ annulus and 13.3/8″ x 9.5/8″ annulus for any activity. Fill both annulus with mud. Perforate 9.5/8″ x 13.3/8″ casing 25m above 20″ shoe with 8 shots per foot. Place a balanced cement plug of 100 Mts. and closing BOP as well as both the annulus squeeze slurry up to 1000psi. Cut and retrieve 9.5/8″, 13.3/8″ and 20″ casing from MLS. Place a balanced plug of at least 100 Mts. starting from 25mtr. below the 9.5/8″ casing cut point up to 10 to 15m below the sea bed. Cut and retrieve 30″ conductor 1 M below sea bed. All casing and protective structures should be removed to the satisfaction of the governing authority for the clearance of location. 18.6.2.4 Testing Plug Cement plug should be tested placing a minimum pipe weight of 15000 lbs. on the cement plug or testing with a minimum pump pressure of 1000psi. 18.7 CEMENTING SAFETY GUIDELINES This cementing guideline is intended to standardize cementing procedures and safety aspects with a view to improve planning, execution and evaluation areas related to cementing services and to reduce occurrences of accidents. The cementing of oil well is an important and highly critical operation which is accomplished in a relatively short period of time. Utmost care should be taken to follow established safety regulations to avoid any untoward accident during cementation. Following are some distinctive features /areas of safety concern associated with cementing operations. 1. Simultaneous presence of a large crew of different disciplines makes coordination extremely essential. 2. Several liquid chemicals and cementing additives used in cementation can cause safety hazards which needs proper precautions while handling. 3. High pressure and air pressure involved in cementing job execution. 4. Simultaneous running of all equipment creating high level of noise pollution. 5. Special attention is required when cementation is being carried out in night time.

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The following guidelines are suggested as good operating practices. It is the responsibility of supervisor to ensure that all cementing service personnel and rig crew adhere to the procedures outlined below: 18.7.1 Pre-Departure Checks of Mobile Cementing Equipment 1. Oil level, HSD level, Radiator water level, Steering hydraulic oil level, battery connections, tyre pressure etc. are to be checked. 2. After initial warm up of engine, check engine oil pressure, water temperature, air pressure, brake application, auto electrical light indications etc. 3. Fire extinguisher, spark arrestor in engine’s exhaust pipes and a first-aid kit should be there in all cementing vehicles. 4. Accessories like high pressure lines, valves, swivels, jet mixers, rubber hoses etc. should be clamped and fastened to avoid any loss and third party injury while plying the cementing vehicle on road. 5. While lifting the cab of cementing vehicle for chassis engine check up/ repair, no person should be allowed to stand underneath the charging pump till the cabin is locked and properly clamped in position. 18.7.2 Safety During on Land Cementation 1. Onshore cementing operator should be well conversant with traffic signals, road safety rules and regulations to minimise road accident. 2. One should never attempt to perform work or drive a vehicle when he is impaired by alcohol or drugs. 3. While reversing a cementing vehicle, one should be certain that the sides and backing area is clear. One should not reverse a vehicle at the facility or on the work location without a guide. 4. One should use the prescribed personal protective safety kits like overhaul, hardhats, safety glasses, hard-toed shoes, hand gloves etc. Wearing of rings, bracelets or neck chains should be avoided while on oil field duty and in repair/ maintenance garage. 5. A pre-job planning meeting should be held to ensure proper job layout and placement of cementing equipment following all safety procedures. 6. Mobile cementing equipment positioning should be planned for quick removal from the work area in case of an emergency. All vehicles should be placed with cabin facing away from the well and wooden wedge support should be placed behind wheels to minimise vibrations and movement of line while pumping operation. 7. Place cementing pump / bunkers / mobile silos at least 1.5 - 2 m apart from other cementing vehicles and at least 25 m distance from the well head. 8. Park all vehicles which are not required for the job to safe areas from the well head so as not to block the well site exits. 9. In hooking of high pressure lines from cementing units, avoid crossing of two discharge lines. Lines should not be run under cementing trucks. Ensure proper anchoring of high pressure lines to prevent accident in case of line failure. 10. Use sufficient number of chicksans to provide more flexibility to discharge lines for reducing vibrations during cementing operations. 11. Do not suspend discharge lines from cementing head without safety chains. Inclined or vertical discharge lines should be tied off to prevent them from being dragged. 241


12. Use only high pressure fittings and approved steel pipes which are in good condition and thoroughly inspected. 13. Cementing heads, manifolds, valves and plugs should be inspected, cleaned and lubricated prior to hooking up. Always clean an oil line connection before making up cementing lines. 14. The cementing operational in-charge must supervise line hook up work and thoroughly inspect prior to testing lines 15. Care should be taken to avoid damage to the threaded pin end and stopper of cementing head during handling and tightening to the casing. Cementing head must be secured to the links by safety chains. 16. Thread protectors must be used on all exposed male threads of circulating subs or cementing heads to avoid thread damage. 17. Only steel lines should be used for releasing pressure and checking back flow from the wells. 18. In electrical rigs, all cementing equipment should be earthed to the derrick structure to avoid any electrical shock accident. Electrical powered cementing skid unit should also be earthed properly. 19. Cementing head, safety valves and high pressure lines of cementing units should be checked for operation at stipulated pressure to ensure operational safety and NDT should be carried out at an interval of 3 years. A. High pressure lines should be tested with water at 1.5 times the maximum pressure expected in pumping operations. The pressure test will not exceed the safe working pressure of the equipment. B. Before, testing all persons should be vacated from the vicinity of high pressure line. No one will be permitted to step across, stand on or straddle or hammer on any pressurised line. C. Do not allow any one to take up line leakage repair operation until – i) Particular well site personnel are notified by the cementing supervisor with the repair plan ii) Pressure has been released from the line. iii) The release valve is left open during repairs. iv) The flow has stopped from the bleed-off line. v) The cementing supervisor has personally observed and determined that the system is free of any pressure. 20. The maximum permissible pressure and pumping rates through cementing lines are as follows: 2" (1.75" ID) -15000 psi W/Pr. - 7 BPM 2" (1.8" ID)-10000 psi W/Pr. - 7.5 BPM 21. During a pre-job safety meeting, cementing in-charge must outline the job procedure, define pressure limits, discuss safety measures and additional briefing on emergency procedure or any unsafe conditions to all personnel designated to participate in the job. He should designate the sequence and volume in which fluid will be pumped and at what pumping rate. Also duties of each person during cementing job including equipment operation, mixing of chemical, operation of valves, bulk delivery, cementing head and maintenance management. He will also review communication system which plays an important role in monitoring cementing job execution. 242


22. Entire sequence of operation should be controlled by cementing operational in-charge (one single supervisor) to avoid any confusion in following instructions during cementation. 23. In many offshore rigs, the cementing unit is placed in relatively congested closed space. The cementing supervisor should ensure that all exhaust fans are working and that all the personnel present in the cementing room should wear air filters (masks). 24. In floaters, the cementing supervisor should ensure that the ventine system which facilitates in cleaning is in proper working condition. If not, the entire cementing room might be filled with unwanted fluids. 18.7.3 Pumping Job 1. All valves in discharge lines shall be checked properly to see that they are open before orders are given to start pumping. 2. No pumping should take place while any personnel is working on, above or below floor level. 3. Flammable or combustible fluids are not to be placed in open displacement tanks on cementing equipment. 4. Acid pumping with cementing units should be avoided, if possible. In case it cannot be avoided, make extra sure that all the valves, caps, lines etc. are fitted correctly and also the least number of people should be present in the vicinity. After the job, the cementing unit and the lines should be washed thoroughly so as to remove any traces of acid 5. When pumping into any system i) Be sure that you have an accurate pressure gauge. ii) Be alert for closed valves also. iii) Start slowly with little throttle to confirm that system is open. 6. A pressure-chart to record pumping pressure continuously should be made available for all cementing jobs. Pressure chart should be supplemented with pumping sequence volume, time and rate. 7. Surface pumping pressure should not exceed the lowest pressure rating of the union and / or whatever connections used such as chicksans, valves, cross-over etc. 8. When transferring or venting material through an open ended hose, a “T” shall be affixed to the end of the hose to prevent the hose from whipping around. The end of the hose should be secured tightly to a stationary object. 9. Cement bunker or mobile cement silo loaded with cement should be kept on jacks at drill site when parked. 10. During slurry, mixing, chemical preparations, adequate precautions must be taken to avoid chemical / additive contact with skin, eyes and clothing. Fumes of defoamer should not be inhaled while using. When handling cement additives, appropriate safety goggles, respirators, dust or vapor masks, face shield, rubber gloves, shoes and hearing protection should be worn. 11. Fluid loss, retarder and dispersant, additives for cement do not contain hazardous ingredients. Primary routes of their entry in human body is by skin contact, eye contact, inhalation and ingestion. Material safety data sheet should be made available at work-center while handling cement additives. 12. Review method and hazard of handling, transferring and chemical mixing as well as proper mixing sequence. 13. Proper illumination with adequate flame proof lighting arrangements should be provided in the operational area especially at slurry mixing point and additive mixing system to ensure safe and effective job coordination during night time. 243


18.7.4 Rig Down 1. Before dismantling the line, pressure must be released to zero. Pressurised line should not be hammered. Tightening or loosening of connections under pressure is strictly prohibited. 2. After pumping has been completed, all pumps, lines and hoses will be flushed before rigging down. All valves and caps on all piping of each unit shall be opened or removed to allow complete drainage of any fluid in the units piping. Piping choked with cement slurry may damage cementing equipment and lead to major breakdown. 3. The air pressure in pneumatic bulk silo / mobile cement silo should be relieved before the vehicles are moved off to location. 4. Transportation of chicksans, high pressure lines, valves, swivels, hoses with end connections from rig floor to ground should be done by winch line only. Throwing down these equipment from derrick floor must be prohibited. 18.7.5 Safety in Cement Bulk Handling Plant 1. All cement silos and other pressurized vessels should be emptied and pressure tested at the specific rating. Safety valves and pressure gauges attached to each vessel should be checked for proper functioning. 2. If any leakage is observed during pressure testing of silos, it should be rectified immediately on top priority. 3. Valves in pipe lines should also be checked for proper isolation. 4. Proper functioning of air dryer should be ensured to get rid of moisture in the air line to silos with a view to prevent cement lump in the system and provide consistent dry cement supply for slurry mixing. 5. The discharge of air, dust and cement from vent line should be directed away from the operational area and preferably in a water pit to avoid air pollution. 6. Personnel concerned with bulk handling plant operation must use all personal protective safety equipment including helmet, goggles, dust mask, ear protection etc.

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Drilling Fluid

CHAPTER - 19

DRILLING FLUID Drilling fluid is an integral part of all drilling operations and hence plays a vital role in designing a cost effective drilling operation. The direct cost of drilling fluid in ONGC is 3% - 5% (approx) of drilling cost as compared to world average of 8% to 10%. However, its impact on total cost of drilling operations is more important. A good drilling fluid therefore not only saves the number of days required to drill a well but also provides a stable and gauged borehole to aid in completion and production operations. Proper preparation and maintenance of a drilling fluid on site is, therefore, a prerequisite for its optimal performance. Though volumes have been written about the composition and field performance of a variety of drilling fluids that have been used over the years, a requirement for a simple stepwise description of activities for preparation and maintenance of conventional and popular water based drilling fluid systems is being felt for many years. This chapter is a humble attempt to bridge this gap of knowledge and experience. The description that follows has been given keeping the man on drill site in view so that it can be utilized as useful ready reference manual of drilling preparation and maintenance on the drill site. DEFINITION Drilling fluid is defined as any fluid, which is circulated in the well bore to help in carrying out a cost effective and efficient drilling operation resulting in stable and gauged borehole to target depth with minimum possible damage to prospective reservoir formations. 19.1 FUNCTIONS The principal functions of the drilling fluid are: • • • • • • • • •

Deliver hydraulic energy upon the formation beneath the bit. Clean the drilling face. Transport drilled cuttings and cavings to the surface. To minimize settling of cuttings and weight material in suspension when circulation is temporarily stopped. To exert sufficient hydrostatic pressure to avoid formation fluid influx. To create an impermeable barrier on the wall. To cool, clean and lubricate the drill string and bit. Stabilize the borehole. To ensure maximum information about the formations penetrated.

19.2 PREPARATION OF DRILLING FLUID FOR SPUDDING A WELL The drilling fluid is needed even before we start drilling a well. In the top hole the fluid is required to flush the hole with pills of drilling fluids of high viscosity and gels to keep the hole clean of cuttings. Drilling fluid is required to be ready in the mud tanks before the well is spudded. The method of preparation stepwise is detailed below. 19.2.1 Preparation of Tanks / Circulatory System of the Rig The drilling fluid is prepared in mud tanks. After preparation the fluid it is pumped in the hole by using mud pumps. It enters the hole through standpipe, Kelly, drill string and finally leaves the drill 245


string through bit nozzles. On its return journey it travels up the annulus and comes out through the bell nipple to the flow line, flow line delivers it to the possum belly of the shale shakers, which are the first in the battery of solids control equipment. The fluid then flows through settling tanks, Desander and Desilter tanks back to active pits through mud flow channels. It is, therefore, necessary to check and prepare the tanks and the circulatory system of the rig before spudding a well. The following steps are required. • Check that active pits and all other tanks are properly placed in order and inter connected properly. • Check all valves for proper functioning and leakage. • Check proper functioning of agitators in the tank. • Check that active pit is properly connected to incoming water line. • Check that active pit is properly connected to mud pumps. • Check that bell nipple is properly lined up and aligned with the return flow line and there is no leakage through welded joints and where it is aligned with return flow line. • Check that there is proper gradient in the return flow line from bell nipple to possum belly to ensure that the flow of mud is smooth and free. • Check that flow line is of sufficient diameter so that it can handle drilling fluid flowing under maximum discharge without getting wasted by spillage. Further it shall also be able to provide allowance for volume enhancement due to gas in flux. • Check the return flow line lands properly in the possum belly causing no mud wastage or spill over. • Check that settling pits, and other tanks of the circulatory systems are properly lined up, have proper valves with no leakage. • Check that solids control equipment like shale shaker, desander and desilter / mud cleaner are properly installed and are ready for operation during drilling. • Check that degasser has been placed properly and has been installed, tested for operation and has been found to be working all right. • Check that motors of hoppers, (superchargers) Desander and Desilter have been properly placed and connected for their smooth operation. Also ensure that these motors have been properly protected / insulated from drilling fluid waste & other water flows etc to avoid their short circuiting and break down. • Check that the sensors of measurement of pit volume, Flow rate, Gas show, Fluid density etc. have been properly installed and secured for their rugged field application. These sensors are installed on mud tanks, flow line, possum belly etc and they provide very useful data to drilling console and mud logging • Ensure that all tanks and the entire circulatory system is clean, by washing it with drill water and removing all unwanted / undesirable matter. 19.2.2 Preparation of Gel Mud The most commonly used drilling fluid being used is water based drilling fluid, which are clay based dispersed , non dispersed and clay free non damaging drilling fluid (NDDF) systems. In application of clay based systems, bentonite clay is one of the most important purchased clay mineral, which is used to prepare initial drilling fluid. This drilling fluid or bentonite suspension in drill water is used to drill the top hole portion of the well. Its preparation requires the following steps: 246

Drilling Fluid

• • •

• •

• • • • • •

Clean the mud tanks thoroughly by flushing them with drill water. Take sufficient quantity of water in the mud tank. Add caustic soda through a small stream of water flowing through a caustic soda bag kept on the tank. This shall ensure sufficient alkalinity of drill water when bentonite powder is mixed with it. Mix bentonite powder through hopper using the water of active pit. The rate of addition of dry bentonite powder is controlled to avoid choking of hopper nozzle. Continue bentonite powder addition till the desired viscosity is achieved. Normally 7.5% bentonite powder weight/volume is sufficient for the purpose. However, thick gels of 10% or more bentonite may also be prepared for keeping as reserve mud in other tanks. Check the pH of the gel under preparation. If it is between 9.0 and 10.5 (depending upon the actual requirement) stop the addition of caustic soda. Run agitators continuously and mud guns intermittently. Keep the gel undisturbed for hydration for 6-8 hours the agitators must be kept off during period of hydration. Close / plug all water lines to avoid inadvertent entry of water in the gel. Avoid contamination of drill water with salt or lime or cement etc. otherwise it shall not hydrate to give desirable viscosity. Avoid contamination of bentonite powder and caustic soda with salt, lime, cement etc.

19.3 CHANGE OVER TO TREATED MUD SYSTEM IN TOP HOLE The bentonite gel prepared in the mud tanks is used for spudding the well. The well is drilled to a depth of 200 mts / 300 mts and the first casing called conductor casing is set to isolate top hole portion from the fluids below. This drilling fluid is then continued for drilling ahead, without any specific treatment. For drilling ahead first the cement set inside the hole is drilled which causes the fluid to get a viscosity hump. The fluid is treated with soda ash, Soda bi carb. Or a combination of Soda bi carb and Citric acid to treat out cement and control the viscosity hump. Minor treatment with thinner may be required to smoother the fluid flow. After the reasonable portion of top hole is drilled and problematic shales / clays are likely to be encountered, the bentonite gel based drilling fluid is converted to treated and dispersed (or non dispersed) inhibitive drilling fluid using Speciality chemicals for control of rheological and filtration properties of drilling fluids. The conversion of bentonite gel to inhibitive dispersed system involves following steps. • Convert the bentonite gel based drilling fluid to inhibitive drilling fluid system during mud circulation with or without drilling ahead. However best conversion is achieved if it is done only during circulation. • Initial viscosity and solid content of the mud needs to be brought down to the practically and operationally affordable limit. Add Chrome lignite and chrome Lignosulphonate in the ratio of 1 : 2. The initial concentration of Chrome lignite be maintained as 0.75% of the mud volume and that of chrome lingo Sulphonate as 1.5% of the mud volume. • Maintain ratio of CL : CLS always as 1 : 2 when ever fresh additions of these chemicals are made. • Add these chemicals through hopper at a uniform rate. 247


•

•

• • •

•

• • • • •

Simultaneously add caustic soda in active mud tank through thin stream of water by putting bags on the active mud tank, to ensure that pH of the drilling fluid in the tank always remains above 9.5. Add Carboxyl Methyl Cellulose (Low Viscosity Grade) through hopper slowly to ensure that the chemical gets mixed uniformly and properly in the drilling fluid. The additive shall help in control of filtration loss. In case the salinity of the drilling fluid is high add Poly Anionic Cellulose (PAC) or Pre Gelatinized Starch (PGS) for fluid loss control. Add Sulphonated Asphalt before encountering troublesome shales, initial dose being 1% to 2% of the mud volume. Add Resinated lignite to this treated inhibitive system at deeper depths to provide better filtration control and formation stability. The initial dose being 1% of the mud volume in circulation. Ensure that all the above listed additions are made slowly over one or two cycles of drilling fluid circulations to ensure that there is no formation of patches and drilling fluid remains homogenous. Add drilling detergent if soft clays are being drilled to avoid bit & stabilizer balling. The dose of Drilling Detergent additions is unto 0.5% w / v of the circulating mud volume. Add EP lubricant specially while drilling directional wells of ‘S’ or ‘L’ profile to minimize torque and drag. The dose of EP lubricant addition is 0.5% w / v of the circulating mud volume. The above two additives are added slowly and directly to the drilling fluid system because these additives are liquids and easily miscible with drilling fluids. Measure the properties of this treated dispersed, inhibitive drilling fluid to ensure that they fall within the limits detailed in Geo – Technical Order (GTO). Add maintenance dosages of these mud additives at regular intervals to ensure that properties of drilling fluid remain within the limits set in GTO.

19.4 DRILLING FLUID PARAMETERS, SIGNIFICANCE& MEASUREMENT 19.4.1 Testing of Drilling Fluid It is necessary to perform certain tests to determine if the mud (drilling fluid) is in proper condition to perform the functions. The frequency of these tests will vary in particular areas depending upon conditions. A standard API form should be provided for reporting the results of these tests. 19.4.2 Density (Mud Weight) Specific gravity weight of a drilling fluid is a very important parameter specified in GTO. The value of specific gravity required may vary in different sections of the hole depending upon control function required either for pressured shale’s / shale’s with dipping beds or it is required to control high formation pressures of permeable formations charged with sub surface gases or liquids. In case the specific gravity of the drilling fluid is required to be maintained in the region of 1.20 / 1.22 or lower, no weighing material is added and solids control equipment are run properly and efficiently to maintain the desired specific gravity. However, if the specific gravity requirement is more than 1.20 / 1.22, barites powder is added in drilling fluid in measured / calculated quantities to achieve the desired higher specific gravity. The 248

Drilling Fluid

Level bubble

Lid

Graduated arm

Rider

Counterweight

Cup

Base

Fig. 1 Mud balance (Source : Manuel du technicien fluides de forage, Milkpark CKS).

stepwise monitoring and control or specific gravity is done as Density may be expressed as pounds per gallon, pounds per cubic foot, grams per cubic centimeter, specific gravity. The mud balance is generally used for mud weight measurement. The weight of a mud cup attached to one end of the beam is balanced on the other end of the beam by a fixed counterweight and a rider free to move along a graduated scale. A level bubble is mounted on the beam. Attachments for extending the range of the balance may be used. Procedure • The instrument base should be set up approximately level. • Fill the clean, dry cup with mud to be tested, put on and rotate the cap until firmly seated. Make sure some of the mud is expelled through the hole in the cap to free trapped air or gas. • Wash or wipe off the mud from the outside of the cup. • Place the beam on the support and balance it by moving the rider along the graduated scale. The beam is horizontal when bubble is on centerline. • Read the density at the side of the rider towards the knife-edge. • Report the density to the nearest 0.1 lb/gal or 0.5 lb/cub.ft. (0.01 gm/cub.cm.) • To convert other units: • Specific gravity = 62.3 lbs per cub.ft. = 8.33 lbs. per gallon Calibration The instrument should be calibrated frequently with fresh water. Fresh water should give a reading of 8.33 lb/gal or 62.3 lb/cub.ft. Or 1,00 gm/cub.cm. at 70 °F. If it shows wrong reading then the balancing screw should be adjusted. 19.4.3 Viscosity and Gel Strength Viscosity is one the most crucial parameters of a drilling fluid as it determines the cuttings carrying capacity of the fluid. The stepwise monitoring of viscosity includes. The following instruments are used to measure the viscosity and /or gel strength of drilling fluids

249


A. Marsh Funnel B. Direct Indicating Viscometer A. Marsh Funnel The marsh funnel is dimensioned so that, by following standard procedures, the out flow time of one quart (946 cub.cm) of fresh water at a temperature of 70 + 5 °F is 26 + 0.5 seconds. A graduated cup is used as a receiver. Procedure 1. Cover the orifice with a finger and pour a freshly taken mud sampling through the screen into the clean, dry, upright funnel until the liquid level reaches the bottom of the screen. 2. Quickly remove the finger and measure the time required for the mud to fill the receiving vessel to the one (quart/946 cub. cm.) mark. 3. Report the result to the nearest second as Marsh Funnel viscosity. ∅ 152mm 20 mesh sieve

1500 cm2

946 cm2

50.8 mm

Inside diameter 4.75 mm

Fig. 2 Marsh viscosity meter

B. Direct Indicating Viscometer Determination of marsh formal viscosity is not enough for proper monitoring and control of drilling fluid viscosity behavior. A six speed Fan make viscometer is used to measure different components of viscosity and this analysis is known as Rheological Analysis. 250

Drilling Fluid

19.4.3.1 Apparent Viscosity The apparent viscosity in centipoises equals the 600 rpm reading divided by 2 [A.V. = ø 600/2 in centipoises] Friction force between two particles is known as Plastic viscosity. Plastic viscosity = Reading at 600 rpm - Reading at 300 rpm. [P.V. = ø600. - ø 300 in centipoises] 19.4.3.2 Yield Point 300 rpm reading - plastic viscosity [Y.P. = ø 300 - PV in lb/100 sq-ft.] 19.4.3.3 Plastic Viscosity (PV)

SPRING DIAL DIAL

ROTOR

BOB ROTOR

Fig. 4 Diagram of a direct - indicating viscometer. Read the deflection of the bob in degrees from a scale on the dial.

Fig. 3 Direct - indicating viscometer

19.4.3.4 Fan Viscometer Procedure i. Place a sample of drilling fluid in a suitable container and immerse the rotor sleeve exactly to the scribed line. Measurement should be made with minimum delay (within five minutes, if 251


possible) and at a temperature as near as practical to that of the mud at the place of sampling (not to differ more than 10 0F or 6 0C). The place of sampling should be stated if required when reporting the values, observed for making a zero error. ii. With the sleeve rotating at 600 rpm, wait for the dial reading to reach a steady value (the time required is dependent on the mud characteristics). Record the dial for 600 rpm. iii. Shift to 300 rpm and wait for the dial reading to come to a steady value. Record the dial reading for 300 rpm. 19.4.4 Gel Strength Thixotropy can be estimated by observing the change in strength taking place in a gel as function of time. Two values, the 10 second gel strength is known as gel0 and the 10 minute gel strength is known as gel10. These two values, can be determined as follows: Allow the mud to stand undisturbed for 10 seconds. Then slowly and steadily rotate at 3 rpm. Allow the mud to stand static for 10 minutes. Then again slowly rotate at 3 rpm. By this calculate gel0 and gel10 in lb/100 sq-ft from dial readings after 10 seconds and after 10 minutes respectively. • Avoid using mud samples which have high foam entrapment, as they shall give false and very high readings of viscosity. • If there is an undesirable increase in viscosity. Analyze the fluid rheology in the drill site lab using multi speed viscometer. • If increase in viscosity of the drilling fluid is due to increase in yield point and gelatin of the drilling fluid add deflocculated like chrome Lignosulphonate to keep the viscosity under control and desirable limits. • If increase in viscosity of the drilling fluid is due to increase in plastic viscosity i.e. amount of undesirable low gravity solids then add bentonite gel for dilution and run solids control equipment more efficiently. • If the viscosity has gone down below acceptable levels due to inadvertent addition of undesirable quantities of water etc. enhance the viscosity by adding high viscosity reserve mud bentonite gel preferably over one cycle time of the drilling fluid. • If there is an abrupt enhancement of viscosity due to gas influx, use degasser to keep the viscosity rise in check. • If there is an abrupt enhancement of viscosity due to contaminants like calcium ions from cement drilling, add soda ash to remove contaminating calcium ions and viscosity returns to normal. 19.4.5 Filtration (Water Loss) The filtration properties of a drilling fluid determine the amount and type of cake it shall form on the face of any permeable formation. The monitoring and control of this property is an important as all other properties discussed before. The step wise discussion of its monitoring and control is given below.

252

Drilling Fluid

Equipment The filtration or wall building property, of a mud is determined by means of a filter press. The tests consists of determining the rate at which the fluid is forced from a filter press containing the mud sample, under specified conditions of time, temperature and pressure, and measuring the thickness of the residual solids film deposited on the filter paper by the loss of fluid. The API filter loss is recorded as the number of cc’s lost in 30 minutes. API high temperature high pressure tests are conducted at 300 deg. F and at 500 psi and recorded as the number of cc lost in 30 minutes. Wheel

Air inlet

Gasket Filter Paper Sieve Gasket Base

Lid Cell Measuring cylinder

Fig. 5 Filter Press for measuring filtrate (Source : Milpark CKS).

Description Essentially, the filter press consists of a cylindrical mud cell having an inside diameter of 3 inch (76.2mm) and a height of at least 2 1/2 inch (64 mm). This chamber is made of materials resistant to strongly alkaline solutions, and is so fitted that a pressure medium can be conveniently admitted into, and bled from the top. Arrangement is also such that a sheet of 9 cm, filter paper can be placed in the bottom of the chamber just above a suitable support. The filtration area is 7.1 + 0.1 sq. inch (45.8 + 0.6 esq.). Below the support is drain tube for discharging the filtrate into a graduated cylinder. Sealing is accomplished with gaskets. The entire assembly is supported by a stand. Pressure can be applied with any non hazardous fluids medium, either gas or liquid. Presses are equipped with pressure regulators and can be obtained with portable pressure cylinders. Procedure i.

Be sure each part of the cell, particularly the screen is clean and dry, and that the gaskets are not distorted or worn. Pour the sample of mud into the cell and complete the assembly. 253


ii.

Place a dry graduated cylinder under the drain tube to receive the filtrate, close the relief value and adjust the regulators so that a pressure of 100 psi (7.03 + 0.356 Kg/sq cm.) is applied in 30 seconds or less. The test period (or duration of time) begins at, the time of pressure application. At the end of 30 minutes, measure the volume of filtrate. Shut off the flow through the pressure regulators and open the relief valve carefully. It may be desirable to use a one-hour filtration tests for oil muds: the time interval shall be reported. iii. Report the volume of filtrate in cubic centimeters (to 0.1 cub.cm.) as the API filtrate. Report at the start of the test mud temperature. iv. Remove the cell from the frame, first making certain that all pressure has been relieved. Disassemble the cell, discard the mud, and use extreme care to save the filter paper with a minimum of disturbance to the cake. Wash the filter cake on the paper with gentle stream of water and measure the thickness of the cake. In case of oil muds diesel may be used in place of water for washing the cake. Report the thickness of the filter cake to the nearest value. • Check and ensure that its value falls within the desirable value of API fluid loss in G.T.O. • Also record and report whether the filtrate is clear liquid or muddy fluid. • If it is muddy fluid report that whether there was a sudden fluid loss as soon as the pressure was applied (Which is called spurt loss). • Measure & report the API fluid loss every six hours during normal drilling operations. • In case the value of API fluid loss increases beyond the acceptable limits as per G.T.O. add fluid loss control additive like CMC, or PAC or PGS depending upon the type of water base mud employed. • Measure the reduction in fluid loss of drilling fluids at least one cycle after addition of Fluid loss control additive to get the true state of the API fluid loss value. • Ensure maintenance doses of fluid loss additive in the drilling fluid system commensurate with amount of fluid dilution with water or bentonite gel and thermal degradation etc of the additive at higher temperature. This shall ensure a more or less stable API fluid loss value within the G.T.O. range. • Keep the API filter press clean, dry, well serviced and maintained for its repeated use. • During API fluid loss measurement keep a watch on the pressure value in the gauge, it should remain at 100 psi throughout. 19.4.6 Sand Content Sand is a type of undesirable low gravity solids that gets incorporated into the drilling fluid system from the sand stone formation being drilled. It is highly damaging to the equipments like mud pumps etc. due to its abrasive nature and hence it is always kept at the minimum possible levels by running desander and desiltters regularly specially when sand stone formations are being drilled. Equipment Sand content of mud is estimated by the use of a sand screen set. The set consists of a 200 mesh sieve 2 1/2 inch (63.5 mm) in diameter, a funnel to fit to screen and glass measuring tube. The measuring tube is marked for the volume of mud to be added in order to read directly the percentage of sand in the bottom of the tube, which is graduated from 0 to 20 percent.

254

Drilling Fluid

Procedure i. Fill the glass measuring tube to the indicated mark with mud. Add water to next mark, close the mouth of the tube and shake vigorously. ii. Pour the mixture, into the clean, wet screen, Discard the liquid passing through the screen. And more water to the tube, shake and again pour onto the screen. Repeat until the wash water passes through clear. Wash the sand retained on the screen to free it of any remaining mud. iii. Fit the funnel upside down over the top of the screen. Slowly invert the assembly and insert the tip of the funnel into the mouth of the glass tube. Wash the sand into the tube by playing of fine spray of water through the screen. Allow the sand to settle. From the graduations on the tube read the volume percent of the sands. iv. Report the sand content of the mud in volume percent. Report the source of the mud sample, i.e. above shaker suction pit etc. Coarse solids other than sand will be retained on the screen. 19.4.7 Liquids and Solids Equipment A retort is used to determine the quantity of liquids and solids in the drilling fluid. Mud is placed in a steel container and heated until the liquid components have been vaporized. The vapors are passed through a condenser and collected in a graduated cylinder and the volume of liquid is measured. Solids, both suspended and dissolved are determined by difference. Procedure i. Procedure will vary slightly, depending upon the apparatus used. Keep the interior of the mud chamber smooth by cleaning after every use. ii. Place a measured volume of deaerated mud in the chamber. Insert fine steel wool above the sample and add a drop of defoaming agent. Close the retort. The hole in the lid of the containing vessel must not be blocked. Put a clean graduated cylinder under the condenser discharge. iii. Heat the retort, continuing 10 minutes after no more condensate is being collected in the graduated cylinder. The addition of a drop of wetting agent promotes separation of oil and water droplets. Read to volume of oil and water collected. iv. From the volumes of oil and water collected and the volume of the original mud samples, the percentage by volume of oil, water and solids in the mud can be calculated. •

Calculate the solids content % by volume as under i. % Water by volume = ml of water x 10 ii. % Oil by volume (if any) = ml. of oil x 10 iii. % Solids by volume = 100 – (ml. of water + ml. of oil) x 10 iv. Gms of oil = ml. of oil x 0.8 v. Gm of water = ml. of water x 1 vi. Gms mud = 10 x sp.gr. of mud vii. Gms of solids = (vi) – (v + iv) viii. MT solid = 10 – (ml. oil + ml. water) ix. Average sp.gr. of solids = (vii) / (viii) 255


x. Solids % by weight xi. High Gravity Solids % by volume (4.3) xii. Low Gravity solids % by volume (2.5)

= = =

(vii) / (vi) x 100 (ix – 2.5) x 55.6 100 - xi

19.4.8 pH Measurement The conventional water based drilling fluids are dependent on specialized additives for their performance. The performance of these additives is in turn largely dependent on the pH value of the mud. If has been observed by laboratory experimentation as well as field experience that the CL / CLS based inhibitive dispersed system perform most efficiently when pH of the drilling fluid lies between 9.5 and 10.5 and hence it is necessary to maintain pH of the drilling fluid always within this range. • The stepwise monitoring and control of pH value of mud is done as under. • Keep a regular check on the pH of the drilling fluid used. The pH of a drilling fluid indicates its relative acidity or alkalinity. Double-distilled water is neutral, that is, it is neither acid nor alkaline. On the pH scale, this point is indicated by the number 7. Acids range from just below 7 for slight acidity less than 1 for the strongest acidity. Alkaline solution range from just above 7 for slight alkalinity to 14 for highest alkalinity. Two methods for measuring the pH of drilling mud are used. These are: i. A modified colorimetric method, using paper test strips. ii The electronic method, using the glass electrode. The paper strip method may not be reliable if the salt concentration of the sample is high. The electrometric method is subjected to error in solutions containing high concentration of sodium ions, unless a special glass electrode is used, or unless suitable correction factors are applied in using the ordinary electrodes. In addition, temperature correction should be made in the electrometric method of measuring pH. 19.4.8.1 Paper Test Strips The test paper is impregnated with dyes of such nature that the colour is dependent upon the pH of the medium in which the paper is placed. A standard colour chart is supplied in a wide range type, which permits estimation of pH to 0.5 unit, and in narrow range papers with which the pH can be estimated to 0.2 unit. Procedure Place 1 inch strip of indicator paper on the surface of the mud. Allow it to remain until the liquid has wetted the surface of the paper and the colour is stabilized. Compare the colour of the upper side of the paper (which has not been in contact with the mud solids) with the colour standard, provided with the test strip and estimate the mud pH. 9.4.8.2 Glass Electrode pH Meter The glass electrodes pH meter consists of a glass electrode system, an electronic amplifier and a meter calibrated in pH units. The electrode system is composed of:

256

Drilling Fluid

i. ii.

The glass electrodes, which consists of a thin walled bulb made of special glass within which is sealed a suitable electrolyte and electrode. The reference electrode, which is, saturated calomel cell. Electrical connection with the mud is established through a saturated solution of potassium chloride contained in a tube surrounding the calomel cell. The electrical potential generated in the glass electrode system by the hydrogen ions in the drilling mud is amplified and operates the calibrated meter, which indicates pH.

Procedure i. Make the necessary adjustment to put the amplifier into operation and standardize the matter with suitable buffer solution, according to directions supplied with the instrument. ii. Wash the tips of the electrodes, gently wipe dry and insert them the mud contained in a small glass vessel. Stir the mud about the electrodes by rotating the containers. iii. Measure the mud pH according to the directions supplied with the instrument. After the meter reading becomes constant, which may require from 30 seconds to several minutes, record the pH. 19.4.9 Methylene Blue Test for Cation Exchange Capacity This test is carried out to know the amount of active clay content of the drilling fluid. This gives an analysis of low gravity solids in the sense that what amount of these solids are active and how much is inert solids. This helps in planning the treatment for control of rheology by control on solids type and behavior. The following materials are required to estimate the cation exchange capacity of drilling mud solids or clays. i. Methylene blue solution (3.74 gm U.S.P. grade methylene blue per 1000 cub.cm.) 1 cm = 0.01 mille equivalent. ii. Hydrogen peroxide - 3% solution. iii. Dilute sulfuric acid (Approx. 5N) iv. One 2.5 cub.cm. or 3 cub.cm. syringe v. Flask, Burette, graduated cylinder, Hot plate, filter paper etc. Procedure i.

Add 1 cc of mud to 10 cc of water in a 250 cc flask. Add 15 cc of 3% hydrogen peroxide and 0.5 cc of dilute sulfuric acid (about 5N) and boil gently for 10 minutes. Dilute to about 50 cc with water.

ii.

Add Methylene blue solution to the flask from a pipette or burette, after each 0.5 cc of methylene blue is titrated into the flask, shake the contents of the flask for about 30 seconds. While the solids are still suspended, remove one-drop liquid with a stirring rod and place it on filter paper. When dye appears as a greenish-blue ring surrounding the dyed solids detected.

iii. Shake the flask an additional two minutes and place another drop on the filter paper. If the blue ring is again evident, the end point has been reached. If the ring does not appear, continue as before until a drop taken after shaking 2 minutes shows a blue tint. 257


iv. Mud as methylene blue capacity, calculated as follows. cc of methylene blue Capacity = ———————————— cc of mud In addition to bentonite that absorb methylene blue. Treatment with hydrogen peroxide is intended to remove the effect of organic materials such as CMC. Polyacrylates, lignosulfonates and lignite. If other absorptive material is not present in significant amounts, the bentonite content of the mud can be estimated as follows. Bentonite in mud (ppb ) = 5 x methylene blue capacity 19.4.10 Filtrate Analysis Such chemical tests are made on mud filtrates to determine the presence of contaminants, such as salt or anhydrite, or to assist in the control of mud properties. For example, the test for alkalinity in high pH muds. The same tests can be applied to make up waters, which in some areas contain dissolved salts, which affect mud treatment. 19.4.11 Alkalinity Determinations Because the pH scale is logarithmic, the alkalinity of a high pH mud can vary up to a considerable amount with no measurable change in pH. In highly alkaline system; analysis of the mud filtrate to determine the alkalinity yield more significant results than pH measurement. Procedure for The Alkalinity Test Measure one or more cubic centimeter of fresh filtrate into a 125 ml flask. i) Add 2 to 3 drops of phenolphthalein indicator solution. ii) Add 0.02 normal (N/50) sulfuric acid from an automatic burette or a pipette, stirring continuously, until the sample turns from pink to colour less, if the sample is so coloured with chemicals that this end point is masked, the end point is then taken when the pH drops to 8.3 using the glass electrodes pH meter. The number of cub.cms. of 0.02 normal (N/50) sulfuric acid divided by the cub.cms. of sample taken is called the “P” alkalinity of the filtrate (Pf). iii) To the sample, which has been titrated to the “P” end point, add 2 to 3 drops of methyl orange indicator solution. Add standard acid drop by drop from the pipette while stirring until the colour of the solution changes from orange to pink. Record as “Mf” to total volume of acid in the cub.cms. used to reach the methyl orange end point, including that of the “P” end point. If the sample is so coloured that the change in colour is not evident, the end point is taken when the pH drops to 4.3 as measured with the glass electrode pH meter. iv) Report the methyl orange alkalinity of the filtrate, ml, as the total cub.cms. of 0.02 normal acid per cubic cm of filtrate required to reach methyl orange end point. 19.4.12 Lime Content Estimation Some knowledge of the amount of excess lime present is of considerable value as an aid in controlling the properties of a lime treated mud. An estimation of lime content can be made based on alkalinity titration of the filtrate and of the whole mud. The titration of the mud must be made rapidly to permit titration of calcium hydroxide and sodium hydroxide without interference from calcium carbonate. 258

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The procedure for estimating the lime content is: i. Measure one cc of mud into a conical flask and dilute to about 50 cc with distilled water. A veterinary syringe is satisfactory for measuring even very thick mud. While a pipette may be used for thinner muds. ii. Add 4 to 5 drops of phenolphthalein indicator solution. A pink colour develops. iii. Add 0.02 normal (N/50) sulfuric acid rapidly from a burette or pipette, stirring continuously, until the colour changes from pink to the colour of the mud. The number of cub.cms. of 0.02 acid divided by cub. cm. of sample taken is called the “P” alkalinity of the mud (Pm). iv. Determine the “P” alkalinity of the filtrate (Pf). v. Determine the lime content as follows: vi. 0.26 (Pm - Pf) = equivalent calcium hydroxide (lb/bbl) vii. where, viii. Pm = cc 0.02 N acid for P of mud ix. Pf = cc 0.02 N acid for P of filtrate 19.4.13 Salinity Analysis / Salt Concentration [Chloride] Test The salt or chloride test is carry significant in areas where salt can contaminate the drilling fluid. Salt water flows, can contaminate the drilling fluid in the hole. Salt tests are among the means of detecting these flows when the chloride content exceeds 600 PPM, it may be necessary to alter the mud program. The test is made on a portion of the original filtrate, or on the sample from the alkalinity test to which a pinch of calcium carbonate has been added. The chloride content test procedure follows. i. Measure a sample of any convenient volume, from one cc to 10 cc, into the conical flask and dilute to about 50 cc with distilled water. ii. Add a few drops of phenolphthalein indicator. If a pink colour develops add sulphuric acid until it completely disappears. If phosphates have been added in large quantities, add 10 to 15 drops of calcium acetate solution. iii. Add four or five drops of potassium chromate indicator to give the sample a bright yellow colour. iv. Add standard silver nitrate solution a drop at a time stirring continuously. The end point of the titration is reached when the sample first changes to orange or brick red. Calculate the chloride (Cl) content as follows. CC of silver nitrate x 1,000 Cl content in mg per liter or PPM = —————————————————— CC of sample in the standard solution If 1.0 cc = 1 mg Cl, or 4.7910 gm of AgNO3 per liter (0.0282N) CC of silver nitrate x 10,000 or = —————————————————— CC of sample in the standard solution If 1.0 cc = 10 mg Cl, or 47.910 gm of AgNO3, per liter (0.282N)

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19.5 DRILLING FLUID ANALYSIS AT DRILL SITE AND ITS SIGNIFICANCE The on site drilling fluid analysis carried out in the well site drilling fluid laboratory provides very useful and valuable information regarding drilling fluids behavior and characteristics. This analysis is essential and very important as it provides the following types of information. • It helps in diagnosis of potential drilling fluid problems and probable down hole complication before the problem gets aggravated. • It serves as a crucial tool in diagnosis of drilling fluid maintenance problems and hence trouble shooting becomes easy, fast and focused. • It helps in monitoring the general health of the drilling fluid and also the effect of treatment on various properties. • It also helps in monitoring the efficacy of different drilling fluid additives in terms of a quality and optimum dose, which helps in optimizing the treatment of right type of additive in right amount. • It also helps in monitoring the optimum performance levels of solids control equipment, and a suitable corrective action may be taken well in time if the performance falls below expected levels. 19.6 TROUBLE SHOOTING OF DRILLING FLUID RELATED PROBLEMS The foregoing description of methods of drilling fluid maintenance and drilling fluid analysis at drill site with its significance are the key guiding principles of maintaining drilling fluid parameters within desirable limit or as per G.T.O. as the case may be. More often than not, however, the drilling fluid engineer on site encounters situations when these vital drilling fluid parameters go beyond windows of acceptable range. In such case an early action is recommended which involves diagnosis of the cause of trouble and then trouble shooting the same by most appropriate and cost effective remedial action. The details of various recommended trouble shooting procedure are given below based on the types of trouble encountered. 19.6.1 Rise in Specific Gravity • Every section of the hole is drilled with a certain desirable specific gravity range based on the pore pressure and fracture pressure values of the formation exposed in that section of the hole. Besides control of pressured and highly dipping formations also some times require higher values of specific gravity of drilling fluid. If however the specific gravity of drilling fluid rises above the desired values the main cause is accumulation or build up low gravity solids which must be curtailed and thrown out to keep the specific gravity of the drilling fluid in check. Following step wise procedure is recommended for trouble shooting this event. • Check the type of formation being drilled, if it is sand, silt, or compact shales than the specific gravity build up is due to inefficient application of solids control equipment. • Check the shale shaker for efficiency and screen size ensure proper size screens are installed. Preferably 60 or 80mesh at the bottom if the prevalent flow rates permit the same. • Make sure that integrity of screens is intact & they are not torn. If torn replace them immediately. • Do not bypass shale shakers to avoid mud wastage through them in case of high flow rates instead enhance their efficiency by their proper servicing and maintenance. • Always ensure thorough and regular cleaning of shaker screens for its optimum efficiency. • Check the desander cones for their efficiency. This can be done by checking the desirable pressure developed on the head of hydro cyclones. If there is leakage get it rectified immediately. 260

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Ensure that cones are in good condition and they are not mud cut. Ensure that the nozzle size of desander is proper. This can be checked by inserting finger through the nozzle while desander is running. If a distinct force is experienced by the finger tending to suck it in, the nozzle size of the desander is correct. This force is developed due to central portion created in an efficient vortex of a hydro cyclone. Watch the discharge of cones, it must be a spray discharge. If any time rope discharge is observed get the cone checked and corrected immediately. Rope discharge means inefficient operation of hydro cyclone (desander & desilter). During round trip, clean and service the cones of desander & desilters for their efficient operation in next cycle. Measure the specific gravity of under flow (i.e. discharge of cones. This shall give an idea of efficient running of desander. Follow all above guidelines for proper operation. Maintenance, and servicing of the desilter also. Run both desander and desilter simultaneously to remove the undesirable low gravity solids upto silt range. This shall certainly reduce the specific gravity of drilling fluid and it may come within the desirable range. Once the specific gravity has come within desirable range maintain it at that level by prudent alternate operation of desander or desilter and efficient use of shale shaker. Use Linear Motion shale shaker and Linear Motion Mud cleaner if available, for most efficient solids control results. In case the formation being drilled is soft clay, the rise in specific gravity is due to particles finer than silt range and a good number of them may fall in colloidal size range. The only option for their control and weight reduction is by dilution with base liquid i.e. water or brine as the case may be hence dilute with water at an optimal rate commensurate with rate of drilling (ROP) to nullify the effect of clay solids getting mixed in the system. For every cubic meter of water being added. Add desired quantities of caustic soda for maintaining pH, fluid loss control additive, and other speciality additives composed in the prevalent mud so that their percentage dosages are maintained. Once the specific gravity reaches desirable value minimize water or base fluid addition along with other chemicals and additives, to a level to maintain specific gravity at that desired level.

19.6.2 Fall in Specific Gravity The fall in specific gravity in case of weighted drilling fluids is a rare phenomenon. However, if it occurs, an immediate remedial action must be initiated before the control on the formation is lost and the well becomes active. The following steps are recommended to trouble shoot this problem. • Check if there was an inadvertent mixing of water or low gravity fluid in the active circulatory system of drilling fluid. It may be due to a leaking tap or valve failure allowing transfer of water or low gravity fluid like reserve bentonite gel in the active system. If such is the case rectify the cause of dilution of drilling fluid immediately. • Measure the present specific gravity of the drilling fluid and add calculated amount of weighting material i.e. barites over one or two cycles, homogenously till the fluid specific gravity reaches back again to the desired value. • In case the fall in specific gravity is due to undesirably low viscosity of the drilling fluid, which is unable to suspend barites in the system, then build up viscosity immediately by adding 261


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highly viscous bentonite suspension till it is able to suspend barites again for desired specific gravity. Add more barites to compensate for the added low specific gravity, high viscosity gel. Maintain the desired specific gravity of mud by ensuring the minimum required viscosity to suspend the weight material.

19.6.3 Rise in Viscosity This is one of the most common problem encountered during operations and needs proper diagnosis after careful analysis of the causes of the problem. The causes of high viscosity or unacceptable rise in viscosity may be due to one or more of the following reasons. • Drilling through bentonitic/ Montmorillonite mud making shales for example gumbo shales in western offshore, Mehsana etc. • Contamination of drilling fluid with monovalent or divalent cation eg: Ca++ contamination while drilling through cement and Na+ / Ca++ / Mg++ contamination while salt-water flow are encountered through pressured formations. • Effect of high temperature in excess of 1200C, specially if drilling fluid is subjected to this bottom hole temperature under static condition over prolonged periods eg: while tripping long hole sections shut down due to surface or subsurface complication etc • Accumulation of excessive amount of low gravity solids though un-reactive is due to inefficient operation of solids control equipment. Depending upon the cause of rise in viscosity following steps is recommended to trouble shoot this problem. • Analyse the drilling fluid in well site laboratory using a multi speed viscometer. • Calculate plastic viscosity, yield point and 10 second and 10 minute gel strength of the fluid. • Compare these results with the results of the fluid just before the rise in viscosity occurred. • In case there is a substantial increase in yield point and gel values and that too more in 10 minute gel values of drilling fluid and the formation being drilled are Montmorillonite rich mud making shales, dilute the drilling fluid sufficiently to keep the colloidal clay content within limits. • Add deflocculant along with caustic soda in sufficient quantities to get the drilled clays all in deflocculated condition. • Add other ingredients of drilling fluid like Chrome Lignite, drilling detergent, caustic soda, fluid loss control additive etc. to make up for the dilution rate so that their optimum percentage doses are always maintained in the drilling fluid. • Continue the above treatment till the viscosity comes back to desired level or range. • Maintain the viscosity of this level by frequent and regular treatments of above chemicals so long as the problematic shale section is under drilling fluids is cased. • In case there is rise in viscosity associated with rise in yield point and gels but the formation being drilled are relatively inert to the drilling fluid partial thermal degradation of deflocculant along with reaction of clay with caustic soda at this temperature (> 1200C / 1500C or more) may be the cause of this unacceptable rise in viscosity. • Add replenishment dosages of deflocculant after every 2-3 cycles so that they never fall below minimum required levels. • Add sufficient quantity of fresh gels (of lower viscosity) and caustic soda to replenish the reacted components. 262

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Always keep pH in the range of 9.5 to 10.5. Maintain the above treatment plan to ensure viscosity in the desirable range. Add resinated lignite for high temperature fluid loss control and Sulphonated Asphalt for better bore hole stabilization. This combination not only provides a good gauge borehole better mud lubricity but also contributes significantly to the high temperature rheology stabilization of clay based inhibitive dispersed drilling fluids. In case the cement is being drilled or there is a significant salt water flow contaminating the fresh water drilling fluid the resultant rise in viscosity shall invariably be associated with high values of yield point and gels. The drilling fluid in such cases is in flocculated state. If it is cement drilling Add soda ash to treat out cement. Add deflocculant like CLS to bring the drilling fluid back to in its original deflocculated state. Since cement provides for alkalinity maintain pH between 9.5 and 10.5 while adding deflocculant. The pH value should not be allowed to fall below 9.5 If it is due to contamination by salt water flows etc isolate the patch of mud which is highly flocculated in a separate tank. Add barytes to drilling fluid to raise its specific gravity so as to stop the salt water flow from the formation. Treat the mud with deflocculant and caustic soda to bring the viscosity back to the normal range. Add other chemicals also like fluid loss control agent, chrome lignite, Shale stabilizer etc. So as to maintain their dosages after dilution with formation water flows. Maintain specific gravity of the mud above the formation pressures to keep any further influx of undesirable formation fluids.

19.6.4 Fall in Viscosity Although the unacceptable fall in viscosity is phenomenon of lesser occurrence, it is equally important. If it is not rectified promptly it may lead to settling of cuttings and barytes in the well bore causing stuck up due to cuttings pack off and mud loss due to resultant pressure buildup below the packed up well bore. The main cause of this is dilution of mud accidentally or gradually to a level that percentages of viscosifier go down below minimum required limits.The steps wise recommendations to trouble shoot this problem is as under: • Add viscosity building thick bentonite gel to the active circulating drilling fluid system in sufficient quantities preferably over a cycle. • Continue above addition till the viscosity rises again to the desired range. • Prepare a viscous pill of bentonite with some lime and CMC and circulate it through the bottom of the hole. This shall unload the well of any settled cuttings etc and clear the borehole of such undesirable loading of solids. • Maintain addition of high viscosity bentonite gels while drilling through patches of inert formations like clean sand stones or other hard rock areas. 19.6.5 Fluid Loss and Control In relatively deeper sections of the hole, a prudent fluid loss control regime is necessary to avoid uncontrolled flow of drilling fluid’s liquid phase to formation pores and channels. This requirement 263


becomes even more important when permeable sand stone sections are drilled. If fluid loss values of the drilling fluid goes above the desired limits and permeable formations are exposed, the risk of a differential stuck up gets greatly enhanced due to formation of a thick fluffy bentonite cake against the formation face of the well bore. It is therefore, essential to keep the fluid loss value within desirable limits and for that following steps are recommended. • If the fluid loss values has gone above desirable limit check the type of cake deposited on the filter paper. Also check if there was a spurt loss when the fluid loss was measured using API filter press. Normally both spurt loss and a fluffy cake shall be observed. • Check the mud rheological parameter, if the viscosity yield point and gels are within the desired limit, add fluid loss control additive over a cycle so as gets its homogenized mixing with the fluid. • Let the mud be conditioned for one more cycle after addition of fluid loss additive. • After that measure API fluid loss again and observe and record the drop in fluid loss value, spurt loss if any and quality of mud cake. • If the new fluid loss value falls within desirable range and there is no spurt loss and cake has become thin & tough in appearance, the desired percentage of Fluid loss additive is achieved in the system. • Maintain this desired dosage by regular intermittent treatment of the fluid loss additive depending upon the rate of drilling and rate of dilution of drilling fluid with water and / or bentonitic gel. • If the new fluid loss value does not fall within desirable range continue addition of fluid loss additive as per above procedure till the desired value of API fluid loss is achieved. • If the rise in fluid loss value of the drilling fluid is associated with concurrent rise in viscosity, yield point and gels, the drilling fluid is flocculated. Add sufficient quantity of deflocculant eg; CLS and caustic soda till viscosity / Rheology parameter fall within desirable limits • Measure API fluid loss again of the deflocculated drilling fluid system. It is likely to have desired values of fluid loss, otherwise small quantities of fluid loss agents may be required to bring the fluid loss to desirable levels. 19.7 SPECIAL OPERATIONS RELATED TO DRILLING FLUIDS The most important and vital of uncertainties related to drilling fluid are down hole complications encountered during drilling important and specially modified / treated drilling fluid or other fluids are employed to successfully tide over these problems or complications. The down hole complication visà-vis the role of drilling fluid engineer in handling them are given below. 19.7.1 Loss Circulation-Detection and Control Loss of circulation or mud loss is one of the most common down hole complication encountered during drilling. This is a condition in which drilling fluid or mud is lost to subsurface formations either partially or completely. In case of partial losses there are partial returns and in case of complete losses there are no returns. The loss of circulation may result due to highly permeable and unconsolidated formations at shallow depths and in such case the losses are partial and these are known as seepage losses. The loss of circulation at deeper depths occurs in fractures, these fractures may be natural or induced. The losses here may be partial to total depending upon severity of fractures. Even if the losses are partial initially and suitable measures are not taken in time, their amount increases and 264

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they become total or near total to widening of already existing fractures. Total losses are also common in lime stone formations (eg. Mumbai High L-III Reservoir) due to presence of vugs and cavern. The first and foremost step recommended for loss of circulation is its early detection. The following is recommended. • Always monitor volumes of active pit closely and regularly any volume additions and transfers must be in variably recorded. • Always monitor return from the well at the shale shaker. • Ensure there are no leakage or surfaces losses of the drilling fluid. • Any significant reduction in active pit volume along with reduction in return flow is an indicative of loss of circulation. • Severe partial loss or total loss is easily detected as there is a fast reduction in active pit volume and almost no return on the shale shaker. • The moment loss of circulation is observed, stop drilling ahead and circulate drilling fluid at lower pump rates. Monitor active pit volumes for calculating the rate of loss. • Analyze & identify the probable zone of loss, in competent formations it is usually just below the casing seat of the previous casing. • Mix a pill of bridging materials like Mica flakes, Walnut shells, Rice husk, Sawdust, Baggage, etc in the separate tank. • Always try to mix pill with a blend of bridging materials like, flaky Mica flakes and granular walnut shell be use do to mix an effective LCM pill. • Mix sufficient quantity of bridging material to make the pill. An effective pill should have 30 lbs / bbl of the material mixed in drilling fluid being used. • Use equal portions of different components for blending the bridging material mixture. • Pump and place the pill slowly against the zone of loss. • Meanwhile, if the loss is below the casing shoe, pull out the string upto the casing shoe and stop circulation of drilling fluid while LCM pill is being prepared in the pits. • Circulate drilling fluid to cut down specific gravity of the fluid by dilution with bentonite gel. • Ensure that hole is always kept full of drilling fluid to avoid well bore instability and influx of fluids from the pressurized formations. • Once the pill is placed against the zone of loss allow time for healing of the fracture by bridging materials of the pill. • If the loss is contained under static condition after application of LCM pill, restart circulation of the fluid at reduced pump strokes and observe for any loss of circulation under these conditions. • If there is no loss now, stop circulation and run in the string slowly to the bottom. • Restart circulation at reduced pump rates and circulate for one or two cycles to ensure that problem of loss circulation has bee tackled successfully. • If the well bore and formation pressures permit further reduce specific gravity by bentonitic gel dilution to the lowest permissible safe limits. • Resume drilling to next casing depth and case the section to avoid any recurrence of losses. • After a loss ensure that all tripping operations, and running in of casing pipe etc must be handled very slowly and smoothly. No pressures surges are allowed, as that shall aggravate the problem. 265


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In case bridging materials fail to seal the zone of lost circulation try other materials like Diesel M plugs. Diesel oil bentonite plugs (DOB plugs) or diesel oil bentonite cement plugs (DOBC plugs) If the above also fail pump appropriate quantity of cement slurry to seal the zone of loss. Losses to buggy or cavernous lime stone formations are not controlled by any of the above formulations. For such losses try thermosetting cross linked Gauss Gum based formulations (Thermo gel). Their gels are acid soluble and hence may also be applied for controlling losses in pay zones or reservoirs. In case losses are severe and total in huge caverns in lime stone formations down hole, drill blind with water and set casing as soon as the loss zone is drilled through. Use drillable plugs for controlling such losses, if available. These plugs are set inside the borehole including the loss zone. The plugs then can be drilled through and they provide protection against losses to such severe loss zones. Never use bridging materials, cement etc for controlling losses in reservoir or pay zones as they shall permanently damage the reservoir formation. Always ensure that bridging material particle size is smaller than bit nozzle otherwise it shall choke them. In case larger particle size bridging materials is to be used, pull out of hole and run-in with open end drill pile to pump such material. Follow good drilling practices to avoid pressure surges in the well bore.

19.7.2 Stuck Up- Detection and Control Stuck up is also one of the most common down hole problems leading to drilling complication. The problem has become more frequent and important in the light of greater number of directional wells being drilled in quest for more oil and greater recovery. Since the drill string has an unequal load distribution i.e. heavier BHA and no hole is truly vertical (i.e.00) a good portion of the string bears against the side of the well bore. This becomes more complicated and amplified in case of directional wells. With such a situation prevalent down hole, if string becomes motion less even for small periods of time and there is sufficient pressure differential i.e. Ä P = Pm – Pf (where Pm = pressure of the mud column and Pf = formation pressure), there is a very high risk of drill string getting stuck up in the filter cake of the borehole wall. Such a condition is called differential sticking. Differential sticking is only a type of stuck up. Besides the string may also get stuck due to a crooked hole. In this case a portion of the string goes inside the bore hole wall where the hole is crooked (popularly called a dog leg). The string forms a seat for itself there and hence this type of stuck up is called a ‘Key-Seat’. The third type of stuck up may occur due to packing off of annulus with cuttings. If the mud rheology is not proper or the rate of cleaning / cleaning efficiency of drilling fluid is much lower than required for whatever, reasons, the cuttings / cavings accumulate in the annulus and pack off the annular space between the string and the bore hole so tightly that it gets stuck. Whatever may be the type of stuck up, it is necessary to act immediately to liquidate the problem because with time the stuck up may become more complicated and severe which sometimes may cause costly fishing sobs, side tracks or even well abandonment.

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Trouble Shooting • Identify and record the moment stuck up occurs on the well site. It is very easily to identify a stuck pipe, which can neither be rotated nor be moved up and down. • Find out the type of stuck up for this correlate well parameters, with immediate well history, BHA configuration, type of formation, presence of open hole dog legs, drilling fluid rheology and hole cleaning pattern vis-à-vis rate of drilling etc. • In case, the BHA is against a highly permeable formation being drilled, and the pipe has remained motion less against this formation for a considerable period of time there are no severe dog legs and mud viscosity is sufficient for effective hole cleaning then most probably it is a differential stuck up. • Once differential stuck up is established calculate the annular volume required to cover the entire BHA length. • Mix a spotting fluid pill in HSD twice the above calculated annular volume to cover the BHA. • Pimp this pill of spotting fluid slowly through a cementing unit and place it in the annulus against the BHA, so that it completely soaks the BHA of the string. • Displace only small quantities of the pill at a time. • After every displacement wait for 30-45 minutes for the pill to react with the cake etc. in which drill string is stuck. • Intermittently work on the pipe to see if it is free. • A differentially stuck pipe shall come out free even in one proper application of spotting fluid. • If the string does not get released even after 6 hours or so of the above spotting exercise then repeat the whole process of spotting against the stuck zone and follow the steps just as described. • The differentially stuck string shall come out free if spotting fluid quality is good and proper procedure as outlined above is followed. • If the stuck up is due to a key seat in which case the string can be moved downwards only but it can neither be rotated nor it can be moved upwards, the spotting fluid shall not help in freeing the pipe, follow fishing techniques to liquidate the problem. • If the stuck up is due to annular pack off associated with poor returns of fluid on the shaker screen, low viscosity or very high drilling rate or excessive caving which prevents proper cleaning of the annulus stop drilling ahead immediately. • Stop circulation or circulate at such a low rate that shall not cause pressure build up and induced fracture below the pack off zone. Otherwise loss of circulation shall also start. • Prepare a high viscosity pill in a separate tank by using thick bentonite gel, CMC, lime and high viscosity grade polymers if any available on the site. • Pump this viscous pill to sweep off the cuttings etc from the annulus. • Continue circulation at rates low enough to keep the annular pressure losses low but sufficient to raise the mass of cuttings etc. packing off annulus to the well mouth. • Once the hole annulus is unloaded, condition the drilling fluid to have sufficient viscosity to clean the hole efficiently. • If hole is prone to caving due to dipping formations or pressured shales, raise specific gravity to minimize this caving so that combination of drilling fluid viscosity and flow rate can effectively clean the annulus. 267


19.7.3 Gas Influx-detection and Control Permeable formation charged with high-pressure hydrocarbons are the objectives of all oil well drilling operations. In the process of drilling for exploration of new areas a number of times permeable formation containing pressured fluids, mainly gaseous, are encountered. If the pressures of these formations are not known at the planning stage the existing drilling fluid may not be able to contain or check these pressures and the formation pressure (Pf) at that point of time exceeds the pressure exerted by the column of drilling fluid (Pm) i.e. Pf > Pm. In such a case the formation gases, which may be hydrocarbons, flow into the well bore with great force and in large volumes. These gases expand tremendously in their journey upwards due to reduction in pressure and very large volumes mixed in drilling fluids manifest at the well mouth. This situation is known as “Gas Influx.” If an early detection and control is not taken up, the influx increase exponentially with time due to tremendous reduction of weight of the mud column in the annulus and it may cause entire annulus to become empty of any liquid drilling fluid whatsoever. The gas than flows in large volumes and with great speed to well mouth and well must be immediately shut in by closing suitable rams of blowout preventer. Such a situation is known as “Kick”. Once a “Kick” is encountered and well shut in, it must be killed by pumping in heavy mud through the string and / or Annulus. However if Kick is not controlled immediately the uncontrolled flow of gas or oil & gas both starts from the drilled hole. If this flow is a mix of hydrocarbons it soon catches fire and the entire rig is burnt down. This is a major crisis situation and is known as “Blow out “. Blowouts need to be prevented because it causes loss of man, material and even the well. A number of times the well gets collapsed and requires abandonment. If the downhole problem of Gas Influx is detected early and a suitable remedial action is properly planned and executed, it is possible to avoid complications like Kick and Blowout. The following steps are recommended for detection and control of Gas Influx during drilling operation. • Maintain a close watch on viscosity and specific gravity of mud while drilling through a permeable formation like sand stone etc. • Measure their parameters of viscosity and specific gravity of out coming mud more frequently say after every 15-20 minutes interval especially if gas influx is anticipated. • A sudden rise in viscosity of the out coming drilling fluid with an enhanced flow rate at the shale shaker indicates gas influx. • Check for flow rate in the return line with driller, an increase shall confirm gas influx. • Check if the pump rate is same or increased. Increase in pump rate reconfirms the gas influx. • Immediately start the degasser & stop drilling ahead. • Check the specific gravity of out coming mud immediately and frequently i.e. every 5 minutes. • Adjust circulation rate to avoid over flow of drilling fluid at the shales shaker to avoid wastage of drilling fluid. • Start raising the specific gravity of ingoing active pit. • Stop circulation for a while and check for self flow. • Shut in pipe rams of Blow out preventer and record shut in pressures developed in the annulus. • Discuss and decide on killing method with the drilling Engineer and follow the exact guidelines on kill mud weight requirement in terms of specific gravity and volume of the kill mud required. • Prepare kill mud of the desired specific gravity at the fastest possible pace in a separate mud tank. 268

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Once the kill mud is ready coordinate with the Drilling Engineer of the rig for its proper pumping and placement in the well to kill the well. Once the high pressure gas influx is controlled by killing operation, resume mud circulation with a higher specific gravity which must be more than formation pressure (i.e. Pm new > Pf) Continue circulation with new higher specific gravity drilling fluid for one or two cycles stop circulation intermittently and check for self flow. There should be no self flow or gas influx. Resume normal drilling operation with new higher specific gravity mud.

19.7.4 Caving – Detection and Control Borehole instability is one of the most common down hole complications encountered in oil well drilling. Most of this instability manifests itself in the form of caving of the shale formations under different well bore conditions of pressure temperature and depth. Though caving always results in an over gauge hole with large washed out sections but the causes of cavings may vary depending upon the type of shales being drilled and drilling conditions and environment. It is therefore very important to carefully analyze every incidence of caving independently to asses its real cause and then follow the best course of remedial action. The indirect cost and losses due to cavings may be enormous, because it may result in poor cementation, costly cement repair jobs, hole fill up, annular pack off resulting in stuck up and mud loss etc. It therefore, needs adequate importance and attention for its detection and control. The following steps are recommended for proper detection and control of cavings while drilling: • Monitor the cuttings return both in quantity and type while drilling through caving prone shale sections specially during bottoms up timings. • Large chunks of formation in large quantities at the shale shaker are indicative of cavings. • Stop drilling ahead, circulate with a viscous pill to clear the annulus of cavings. • Simultaneously condition the drilling fluid with sufficient quantities of shale stabilizer like sulphonated asphalt over one cycle. • Also ensure that sufficient quantities of all other components are present in the drilling fluid like CMC, CL, CLS and Resinex (for higher temperature regimes) to ensure the best possible values of Rheology and filtration loss. • Follow good drilling practices, avoid pressure surges due to very fast running in etc. • If the cavings are due to pressure, tectonically stressed and / or highly dipping formations, raise the specific gravity of the drilling fluid to counter balance these pressure. • Use KCl or NaCl salt (3% - 5% or even more) in the drilling fluid composition to ionically balance the caving prone formations. • Keep the hole flushing regime of the annulus commensurate with drilling and caving rate to avoid complications due to annular loading with these cuttings / cavings. 19.8 PREPARATION OF WELL FOR CEMENTATION Though drilling fluid’s primary function is to aid in conduct of a cost effective and smooth drilling operation, its role gets extended as a compatible interface for other related operations like cementation of casing pipe to case the drilled well bore. The success of cementation job depends on getting a good cement bond both at the well bore and at the casing pipe faces which in turn depends on the quality of well bore. Drilling fluid is therefore, required primarily to provide a gauged and stable borehole so that it is possible to properly place the required amount of cement slurry in place besides the 269


following is also recommended from drilling fluid’s angle while preparing a well for cementation job: • Circulate and condition the drilling fluid after the casing pipe has been lowered to the desired depth for 2 or 3 cycles. • In the first cycle ensure that the casing open hole annulus gets cleared off all debris / cavings, or left over cuttings from the annulus by suitable mud Rheology / hydraulic combination in new annular geometry. • In the next one or two cycles treat the drilling fluid with suitable quantities of deflocculant (i.e. CL/CLS combination) and fluid loss control additive (i.e. CMC, PAC, PGS or Resinex as the case may be) to ensure that drilling fluid has low plastic viscosity and yield point values and it deposited a thin cake on the wall. • Ensure that at this Rheology it shall be possible to effectively remove all drilling fluid from the well bore and casing. • Once the desired drilling fluid parameters are achieved, start cementation operation without intervening avoidable delays or wait otherwise the well bore condition may deteriorate. 19.9 WELL PREPARATION FOR PRODUCTION TESTING Production testing is also another operation which has an interface with drilling operation. The well after successful hermetical testing is taken up for production testing. The following is recommended as regards managing drilling fluid during these operation: • In cased hole completions, perforation is carried out in the selected reservoir or pay zone intervals called objects. Use non damaging brine (NaCl or CaCl2 brine) for carrying out perforation to minimize formation damage. • Prepare brine as completion fluid in a separate clean tank and it should be free from all debris clays solids etc. of the tank and flow channel. • Replace the drilling fluid of the hole by this brine and store it in a separate tank. • Use water as spacer between brine and drilling fluid to avoid contamination of brine with drilling fluid solids. • In case well is required to be killed, displace brine with drilling fluid use water as spacer to separate the two fluids. • Always keep the drilling fluid in good usable condition in reserve tanks for any eventuality during production testing operation condition and treat the drilling fluid intermittently if production testing operations get spread over extended period of time. 19.10 GUIDELINES FOR RUNNING PHPA MUD The following guidelines for running PHPA muds are based on careful analysis of field operating experience. • Ensure that the rig has adequate solids control equipment. If the solids control equipment is inadequate, then massive dilution will be required to retain control of the solids. The low gravity solids should be maintained at less than 5% by volume. • Maintain at least 1 lbm / bbl [2.9 Kg / m3] active PHPA in the mud system as determined by a materials balance calculation. The PHPA depletes from the system as it coats on the solids and the well bore. There are several methods to test for PHPA concentration in the mud. At present, the best way to ensure that there is enough PHPA in the system is to make sure that an excess is added with each unit volume of dilution. 270

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To maintain the mud system, mix whole new mud in a separate pit and add this premix to the system. Product concentrations in the premix can be adjusted if necessary to increase product concentration in the active system. The premix should be sheared at high shear rates prior to adding to the active system. The premix technique will minimize temporary viscosity fluctuations caused by the addition of new product and will also facilitate the materials balance calculation. When mixing the mud, use a shearing device to eliminate viscosity hump problems. Alternatively, if the initial viscosity is too high when mixing new mud, mix only one-half of the required PHPA. The remainder of the polymer can be added to the system as soon as circulation commences. PHPA muds are sensitive to high pH, especially in the presence of high calcium levels. For this reason, it is not recommended to drill cement with them unless the system is to be replaced after drilling out. If it is unavoidable to drill cement with a PHPA system, the system should be pretreated preferably with citric acid or sodium bicarbonate to knock out calcium ion and to control pH. If cement contamination occurs, dump excessively contaminated mud and renew the PHPA concentration throughout the whole system. Maintain adequate yield point in the mud. Yield points in the range of 10 to 20 lbs/100 ft2 are considered optimum, with an initial gel of 2 lbs/100 ft2 required to prevent settling of the weight material. The calcium ion concentration in PHPA muds should be run at 400 mg/L maximum. Higher calcium ion levels will interfere with the PHPA polymer. Trying to treat out the calcium completely could lead to self induced carbonate contamination. Maintain the pH in the 8.5 to 9.5 range. The PHPA polymer is sensitive to higher pH and the hydroxide ion acts as a dispersant to clays. PHPA muds can be run at any salinity from fresh water to salt saturation. They are particularly effective in seawater. For greater inhibition sodium chloride at a chloride ion concentration at 125,000 mg/L has been quite effective in many areas. In salt systems, PHPA should be prehydrated in fresh water for maximum yield prior to adding to the active system. Pre-hydrated Bentonite provides base viscosity and is the foundation for fluid loss control, particularly HTHP fluid loss. It is recommended to use 8 to 12 lbm/bbl [23 to 35 Kg/m3] Bentonite depending on salinity, mud weight and the required HTHP fluid loss control. If insufficient yield value or initial gel strength is obtained from the initial mud formulation, Xanthan gum can be used at 0.25 lbm/bbl [0.7 Kg/m3] for temporary viscosity until the final mix is attained. When pre-hydrating Bentonite or when adding barite, it is recommended to add about 0.25 to 0.5 lbm/bbl [0.7 to 1.4 Kg/m3] of poly-acrylate deflocculant (in the premix) to minimize viscosity fluctuations in the active system. Another effective technique to enhance the inhibitive quality of PHPA muds is to use Sulphonated asphalt in concentrations of 6 to 8 lbm/bbl [17 to 23 Kg/m3] to seal shale microfractures. If viscosity increases are noted with increasing drill solids, take steps to reduce drill solids through increased use of solids control equipment or dilution and increase the PHPA concentration in the active system. To control the HTHP at 2500F [1200C], utilize PAC polymer at 1 to 2 lbm/bbl [2.9 to 5.7 Kg/ m3]. To control HTHP at 3000F [1500C], use high temperature fluid loss control polymers (such as vinyl sulfonate / vinyl amide copolymer and modified lignin) to supplement the Bentonite. 271


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Observe the drill cuttings across the shale shaker. If the cuttings stick together when squeezed, additional PHPA polymer may be required. Ideally, the cuttings should have a glossy appearance and have a slippery feel. Furthermore, as a supplement to materials balance calculations, Bentonite pellets immersed in a mud sample or one of the analytical titration techniques may be used. Observe the cuttings size distribution at the shale shaker/ flow line. They should be coarse with a minimum amount of fine particles. If shaker blinding occurs with the PHPA mud in such circumstances, use a shearing device while pre-hydrating the PHPA or switch to the next coarser screen size. When drilling with PHPA muds, tight hole as a result of gauge hole or drill cuttings adhering to the well bore can be encountered. This phenomenon often occurs only in the new hole section drilled and clears up after the first trip through the section. When this situation is encountered, either pull through very slowly or break circulation to ream. When pulling through, watch the weight indictor in order not to pull into a key seat. We should see a bleed down of over pull. With a top drive equipped rig, trip out in the circulate / rotate mode through the new hole section. If tight hole across the same section persists on consecutive trips, investigate other causes. Although PHPA muds stabilize well bores, unconsolidated sands and mechanically weak, shales will still be susceptible to hydraulic and mechanical erosion. In such areas, maintain the proper yield value, use the lowest practical bit and annular hydraulics, and monitor bottom hole assembly and tripping practices.

19.11 NON –DAMAGING DRILLING FLUIDS (DRILL-IN FLUIDS) Formation damage occurring during the drilling of pay-zone sections of vertical as well as inclined wells with or without horizontal drain hole section can be a significant mechanism of ultimate reduced productivity in both oil and gas bearing formations. It can occur when an external solid laden fluid or clean but reactive fluid enters the reservoir. The drilling fluid can cause damage with the filtrate and with the internal filter cake that is formed in the face of the exposed sand. While the external filter cake is formed during the drilling process, a spurt loss occurs that carries fluids and solid particles in to the face of the newly exposed formation, forming the internal filter cake. After the external and internal filter cake is formed, only filtrate will penetrate in the formation through them due to hydrostatic pressure. In order to have a good productive well, the internal filter cake and the filtrate must be expelled with the draw down pressure when the well is set to production. In some cases a combination of petrographic and special core analysis techniques are used to evaluate the potential effectiveness of proposed drilling fluids and procedures for cost and risk analysis prior to the actual implementation. These tests are conducted to obtain a better assessment of the risk associated with the use of proposed drilling fluids and to optimize the fluid and procedures which will be utilized in a given inclined / horizontal or vertical well operation to maximize ultimate productivity of oil or gas. Formation Damage During Overbalanced and Under-balanced Drilling A number of authors have provided a detailed discussion of potential formation damage mechanisms which may occur during overbalanced and underbalanced drilling operations. A summary of this work is provided in the literature. These mechanisms would include:

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1. Mechanically Induced Formation Damage • Physical migration of in-situ fines and mobile particulates. • The introduction of extraneous solids of either an artificial nature (i.e. weighting agents, fluid loss agents, or artificial bridging agents) or naturally occurring drill solids generated by the milling action of the drill bit on the formation. • Relative permeability effects associated with the entrainment of extraneous aqueous or hydrocarbon phases within the porous medium. • Formation damage effects associated with the use of extreme underbalance or overbalance pressure and associated fines migration or spontaneous inhibition phenomena. • Direct mechanical glazing phenomena associated with bit formation interactions. This particular damage mechanism is usually associated with gas drill operations where high bit rock temperature commonly occur. 2. Chemically Induced Formation Damage • Clay induced formation damage associated with the reaction of low salinity or fresh invaded fluid filtrates with potentially reactive clays (swelling clays or mixed layer clays). Low salinity or pH shocks may also results in clay deflocculation phenomena which are a disruption of electrostatic forces which are holding clays in a flocculated state. This phenomena is common in some kaolinite rich reservoirs. • The precipitation of waxes, solids, asphaltenes caused by a reduction in temperature or pressure associated with the drilling processes or incompatibility between introduced hydrocarbon fluids and in-situ hydrocarbon fluids results in a destabilization and precipitation of asphaltenes. • The formation of insoluble precipitates caused by the blending of incompatible drilling and completion filtrates with in-situ connet water. • The generation of high viscosity stable water in oil emulsions in the near well bore region caused by the invasion of incompatible water-based filtrates resulting in the formation of an emulsion blocks. • Wettability alterations associated with the use of invert drilling muds or other muds containing high concentrations of polar surfactants or materials. Near well bore wettability alterations can reduce the relative permeability of oil significantly and increase relative permeability to water, causing a dramatic change in the water-oil production characteristics of a given completion. 3. Biologically Induced Formation Damage The introduction of bacterial agents during drilling and completion is a major concern as problems associated with bacterial growth in porous media can be of a delayed yet significant onset of formation alterations. Major problems associated with bacterially induced damage would include: • Secretion of high molecular weight polysacharide polymers to form plugging bio-films or bioslimes. • Colonization of bacteria onto conductive metal surfaces resulting in pitting and corrosion. • Propagation of sulphate reducing bacteria (a classification of anaerobic bacteria which do not require oxygen to survive) and the resulting metabolization of sulphate present in naturally occurring formation or injection water to toxic hydrogen sulphide gas. 273


4. Stubborn Filter Cake A low permeability filter cake serves an important function in preventing the movement of fines out of the drilling fluid into the formation where the fines can plug pore spaces. However, the filter cake can be a problem when it is difficult to remove, or the removal process releases the fines into the formation. Filter cake is generally broken up or dissolved by the action of completion fluids, breakers, acid soak, or during initial well flow. Often, the best low permeability filter cakes are the most difficult to remove. Many of the problems associated with drilling induced formation damage can be diagnosed through appropriate laboratory simulation techniques and appropriate procedures and fluids developed to mitigate or reduce many of the damages previously mentioned. 19.12 DEVELOPMENT OF NON –DAMAGING DRILLING FLUIDS Drill-in fluids are among the latest solutions in horizontal and extended reach wells. These fluids were designed to act as a conventional drilling emulsion from a well control point of views, but formulated to minimize formation damage and provide for well cleanup and flow back. Drillers switch from conventional fluids to drill-in fluids as the drill bit nears the pay zone. Most drill-in fluids have various types and concentrations of additives to minimize fluid loss to the formation. An optimally designed drill-in fluid should : • Conform to acceptable health, safety and environment standards. • Retain desirable drilling fluid properties. • Bridge all exposed pore openings with a specially sized material. • Deposit a non–damaging filter cake that is easily and effectively removed by initial production. Based on above requirement of non – damaging drilling fluid, IDT has formulated the Non damaging drilling fluids with following additives : • Tap water • XC polymer • Pregelatinised starch • Polyanionic cellulose ( L V and R ) • Micronised Calcium Carbonate • Low Solid formate brine based RESULT AND DISCUSSION ON NDDF 1. All components of NDDF system as mentioned above are environment friendly, specifically XC polymer and pregelatinised starch are biodegradable. Addition of potassium chloride, bactericide (aldehyde or amine type, 500 –1000 ppm) were also done to further enhance performance. For intermediate section KCl – PHPA system with or without clouding glycol has already been proposed for drilling all development wells. Various reports on the systems have been issued from this institute and in-house expertise is also widely available. 2. All desirable drilling fluid characteristics eg. • Sp. Gr. • PH • Rheological properties (AV, PV, Gel-0 and Gel-10) • Filtration Loss (API, HTHP) • Lubricating properties were evaluated. These parameters were determined at ambient temp. and after hot rolling at 90 to 120 deg. C. 274

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Other important properties analyzed were • Swelling characteristics • Cutting disintegration / cutting recovery studies are excellently well . 3. Although some solids invasion and formation damage are inherent to all drilling fluids it is possible to minimize both damage caused by solids invasion and, the depth of this damage , by correctly sizing the bridging particles in drilling fluid. Calcium Carbonate has been used as the main bridging agent as it is readily available in different grind sizes. The pore throat data supplied by the projects indicated that IDT formulated Micronised Calcium Carbonate widely being used in ONGC is suitable as bridging agent for NDDF. 4. Recommended drilling fluids has controlled filteration loss and minimum cake thickness (less than 1 mm). Impermeable nature of the filter cake shows that it can be easily and effectively removed during initial production.

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CHAPTER - 20

EMERGING TECHNOLOGIES 20.1. CASING DRILLING The conventional drilling process for oil and gas utilizes a drill-string made up of drill collars and drill pipe to apply mechanical energy (rotary power and axial load) to the bit, as well as to provide a hydraulic conduit for the drilling fluid. The drill-string is pulled out of the hole each time the bit or bottom hole assembly needs to be changed or the final casing depth is reached. Casing is then run into the hole to furnish permanent access to the well bore.

Casing Drilling – Solutions to: 1. Swelling formations 2. Sloughing formations 4. Swab oil & gas 5. Hole in casing or keyseat

3. Washout 6. Running logs & casing difficulties

The Casing Drilling System (CDS) provides an alternative to the conventional drilling system by using ordinary casing as the drill-string which remains in the hole at all time. In this casing itself serves as the hydraulic conduit and means of transmitting mechanical energy to the bit Thus the well is cased as it is drilled which may reduce well costs or enable problematic hole sections to be drilled. A short wire line retrievable bottom hole assembly (BHA) consisting of at least a bit and expandable under reamer are used for casing drilling apart from casing pipes. Casing drilling allows operators to simultaneously, drill, case, and evaluate oil and gas wells. With casing drilling, the well is drilled with standard oilfield drill bits and other down hole tools are lowered via wire line through the casing and latched to the last joint (bottom most) of casing. 276

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The Casing Drilling system simultaneously drills and cases a well with normal oilfield casing as the drill string. The casing transfers hydraulic and mechanical energy to a wire line-retrievable drilling assembly suspended in a profile nipple located near the bottom of the casing. A drill lock (DLA) in the top of the drilling assembly provides mechanical (axial and torsional) coupling and hydraulic seals to the casing. It also provides a mechanism to facilitate insertion and retrieval from the casing string. The drilling assembly below the DLA terminates in a pilot bit and under reamer but may include other conventional drill string components, such as a mud motor, coring assembly and a directional assembly. In most casing drilling applications, an under reamer is used above a pilot bit to open the hole from the pilot-bit diameter to the final well bore diameter. The pilot bit is sized to pass through the casing, and the under reamer opens the hole to the size that is normally drilled to run casing. The casing drilling system uses a top drive to rotate the casing. Single joints of casing are picked up off the pipe rack and set in the mouse hole. The top drive, with an extend feature, is connected to the top of the joint, which is then stabbed into the top of the casing string in the rotary table. The casing joint is drilled down by using the top drive in a conventional manner. The casing string is rotated for all operations except slide drilling with a motor and bent housing assembly for oriented directional work. One of the most meaningful benefits of casing drilling is the reduction of down hole trouble time. By concurrently casing while drilling, lost circulation and well control incidents have been nearly eliminated thereby enhancing safety. This is particularly key for wells that encounter a weak zone prior to drilling into a higher-pressure zone. Balancing the required procedures for these differing zones has historically been a challenge that can be overcome through casing drilling. The two basic technologies used for Casing Drilling are; 1. The first technology employed by Tesco, uses a bottom hole assembly comprised of a positive displacement motor (PDM), drill bit and hole opener / under reamer. The assembly is latched to the first joint of casing. As the assembly drills ahead, the casing is lowered into the hole, either in a static or rotated mode. The casing connections are normal buttress thread with Multi torque rings for additional torque resistance. Upon reaching total depth (TD), the latch-on bottom hole assembly is recovered with a special retrieval tool. A valve system is run and installed before cementing commences. 2. The second technology adopted by Weatherford, utilizes only casing to transmit rotary torque and weight to the drill bit. A drillable drill bit and valve assembly is made up and run with the first joint of casing. The casing string is rotated during drilling, typically with a spear assembly that provides rotation to the casing. Upon reaching TD, the casing can be cemented immediately, with no need for an additional trip. Advantages & Features of Casing Drilling z Reduces or eliminates drill pipe or wire line trip times z Gets casing to design depth through problem formations z Reduces potential requirement of contingency casing z Reduces the initial surface casing size, because it can go deeper z Drills straighter holes reducing torque, drag and cleaning problems due to spiraling z Reduces open hole exposure time and associated drilling problems z Reduces borehole exposure to formation and completion damage z Reduces or eliminates well control issues of DP tripping z Simplifies well architecture 277

Drilling Operation Practices Manual z z z z z z z z z z z z

Optimizes reservoir production Preserves well bore integrity. Eliminates use of Drill pipe, Heavy Weight Pipe. Also uses less bottom hole assembly to make a complete Well. Thus saves the cost transportation, maintenance and inspection. Eliminates tripping and other pipe-handling which means reduced manpower requirements and related safety incidents. Uses less horsepower required which translates into lower maintenance and lower fuel costs Increases bit hydraulics due to smaller annular clearance. Lighter weight substructure and derrick means reduced capital and logistic costs. Lowers mud and cementing costs due to smaller well bore diameters. Less chances of mud loss even in weak formations due to smearing effect. Volume reduction for Drilling mud, completion fluids and cement slurry. Less drilling time and less completion time. Less drilling cost.

All this eliminates the need for; 1. Reaming. 2. Taking a kick while tripping the drill string. 3. Unintentional sidetracks while reaming back into the hole. 4. Hole problems caused by swab and surge pressures. 5. Key seats and wearing holes in previously set casing. Intangibile benefits of Casing Drilling technology. z

Reduced Stuck Pipe Worldwide experience shows that casing drilling drastically reduces stuck pipe ocurrances.

Formation Related Trouble Time Experienced With Conventional Rigs Is Reduced Faster completion of drilling reduces the exposure time. Elimination of tripping reduces disturbance of formation. z

Drilling safely through depleted zones – Smear / Plastering effect One would normally expect lost circulation to be a potential problem with Casing Drilling because the smaller annular clearance between the casing and borehole wall increases the frictional pressure losses, thus increasing the ECD. In fact, what has been found is that Casing Drilling significantly reduces lost circulation. There is substantive evidence that the Casing Drilling system can be used to drill through weak depleted zones without the massive lost circulation that so frequently occurs when drilling with drill pipe and collars. The exact mechanism that provides this benefit is not proved yet, but it is believed to be the result of mechanically working drilled solids into the face of the borehole. The axial misalignment of the casing that causes coupling wear also provides a constant mechanical force on the rotating couplings to smear drilled cuttings and mud solids into the borehole wall. This plastering effect mechanically builds an impermeable filter cake. z

Improved Well Control Many well control incidents occur while tripping pipe. These well control incidents are avoided with the Casing Drilling process because pipe tripping is eliminated. But some kicks are taken while drilling ahead, and Casing Drilling will not prevent these. z

Faster fishing Through Casing by Wire Line It is possible to conduct conventional fishing operations to recover junk from the hole while Casing Drilling. A fishing operation was conducted using conventional tools (mills, junk baskets, z

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magnets, etc). The only difference was that these tools were run in and out of the hole with the wire line, thus making the process faster than having to trip the drill string each time a fishing run was made. The casing may actually be used similar to wash over pipe to assist in the fishing operation. Smaller Rigs Can Be Used To Drill Wells Wells can be drilled with the Casing Drilling system with smaller rigs than are required for conventional drilling. This has a direct advantage in situations where the rig and a conventional drill string must be transported by helicopter. It also may allow smaller rigs that have been left on platforms for repairs and re completions to be used for sidetracks and infield drilling without needing to bring in a larger rig. z

Reduced Cost Due To Faster Well Completion Improved Operational Efficiency Due To Elimination Of The Pipe Tripping Better Deviation Control For soft formations no particular measure is needed for deviation control. However for harder formations drilling assembly can be changed as often as required to match the cutting structure as per the rock strength. Well deviation is controlled by using a stabilized drilling assembly protruding below the casing. 1. Casing drilling system developed by Tesco Drilling Technology - Casing drilling with retrievable assemblies The technology uses unique rig and down hole equipment that functions as an integrated drilling system. Standard oil field casing is used to transmit mechanical and hydraulic energy to the drill bit. A wire line retrievable drilling assembly that is latched into the casing eliminates the need for tripping with a conventional drill-string. Down hole system A wire line-retrievable BHA attached to the bottom of the casing drills a well bore of adequate size to allow the casing to be advanced freely. The BHA is attached to the bottom of the casing by a landing assembly so that a wire line unit can be used to retrieve and replace it without needing to trip pipe out of the well. The BHA consists of a pilot bit and under reamer that are sized to pass through the “drill-casing.” Thus, it becomes possible to drill a hole while providing adequate clearance for the drill-casing and subsequent cementing. For directional applications, the BHA includes a benthousing down hole motor and measurement-while-drilling (MWD) tool. Other equipment, such as logging-whiledrilling (LWD) or coring equipment, may also be run to perform almost any operation that can be conducted with a conventional drill string.The BHA is run below a landing assembly to transport it into the well and mate up with a special casing shoe joint. Spring-loaded dogs located on the landing assembly engage a no-go groove on the casing shoe. 279


This positions the assembly so that positive-locking axial keys extend into a profile to transmit compressive (bit weight) and tensional drilling loads from the drilling assembly to the casing. A torque anchor mates with recesses in the casing shoe to provide rotation and torque transfer from the casing to the BHA. Seals located on the landing assembly incorporate upward and downward-facing pressure cups that prevent flow around the BHA landing assembly while drilling. A bypass system allows drilling fluid to be circulated, preventing well swabbing and casing sticking when running or retrieving the BHA. A drilling shoe positioned on the bottom of the casing is dressed with either (polycrystalline diamond compact) PDC cutters or tungsten carbide chips, ensuring a full gauge hole is obtained ahead of the casing. The drilling shoe is also designed to facilitate retrieval of the BHA back into the casing as it is pulled. Setting-And-Retrieving Tools A custom-designed, wire line setting-and-retrieving tool is used to install and remove the BHA. A swivel prevents the rotational twist of the braided wire line so that the casing can be rotated during wire line operations. An emergency shear sub, activated when line tension reaches 20,000 lb, provides for a straightpull emergency release of the latch in case tight-hole conditions warrant a disconnect. The design and testing of a pump-down pressure set tool is in progress and an electric retrieving concept is being considered for future application. 280


Casing Drilling Rig Casing drilling can be implemented either with a specially developed drilling rig or by a conventional rig modified for casing drilling. To date, the system has been used only with a rig designed specifically to prove the entire system and to maximize the efficiencies of casing drilling. Special equipment is needed to handle casing in a drilling mode and to handle the wire line retrievable BHA. A top drive must be used to rotate the casing. In addition, a split crown and split traveling blocks facilitate effective wire line access to the top of the casing through a wire line blowout preventor (BOP). A large wire line unit is needed that is sufficient to run and pull the BHA efficiently. Pipe-handling tools for the casing are also required. Tesco has built three rigs that are hybrid casing-drilling and conventional-drilling rigs. A fourth is under construction, exclusively designed for use with the casing-drilling process. In addition to the rig requirements mentioned above, these rigs include other features that allow the entire drilling process to be implemented more effectively. The rigs are designed with hydraulic power units for the mud pump, drawworks, top drive, and wire line unit, reducing equipment weight while taking advantage of the company’s top-drive design. All this equipment is operated under computer control through programmable logic controller interfaces that minimize the potential for human operator error, optimize equipment performance, reduce manpower requirements, and facilitate data acquisition. The wire line unit is installed as an integral part of the rig and is located adjacent to the main drawworks. The hydraulic power and computer control allows the driller to function as the wire line operator from the driller’s control room. The hydraulic drive on the drawworks is very similar to that shown for the wire line unit and acts as a brake that allows the drill string to be advanced with the drawworks under power rather than with the power unit disengaged by a clutch. The initial commercial applications of the casing drilling technology are anticipated to be applied to relatively low-cost land wells. These wells are drilled rapidly, with frequent rig moves; consequently, the mobilization costs can be high. A number of features of the casing-drilling process allow for a lighter rig design. The casing is picked up as single joints from the pipe rack. Thus, it does not need the monkey board, setback area, and heavy derrick associated with a conventional rig. The shorter and smaller derrick reduces wind load considerations, allowing for the construction of a lighter derrick and substructure. Smaller mud pumps can also be used because larger casing IDs significantly reduce the friction loss, as compared to conventional drill pipe and collars. Furthermore, the larger OD of the casing allows adequate annular velocity to be achieved with lower flow rates than otherwise achieved with drill pipe. The overall result is that the rig: z Is not as heavy to move z Requires less capital investment z Uses less power z Requires a smaller crew. Tesco’s patented Casing Drilling process could lower drilling time up to 30% and reduce unscheduled drilling events.

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The Challenges associated with Casing Drilling are: i.

Changing The Bit Or Bottom Hole Assembly Casing Drilling eliminates tripping as we know it and retrieve the down hole tools by wireline through the casing. This will reduce trip time and eliminate the unscheduled events associated with conventional tripping. The down hole tools incorporate both an axial and torsional latching mechanism to anchor the tools to the bottom of the casing so drilling can proceed by rotation of the casing or the use of a mud motor. ii. Tubulars and Casing Connections Casing used with retrievable casing system is generally of same size, weight and grade that would normally be used in a well. However the casing connections may require a change because casing in this case has to provide adequate torsional strength, fatigue resistance and flow clearance. To achieve this buttress connections are used with multi-torque rings for additional torque capacity. Both integral and coupled connections have been used successfully. iii. Drill Bits & Bit Cutting Structure Drilling with casing and wireline retrieving the tools would require that the cutting structure be small enough to pass through the inside diameter of the casing, but have the ability to drill a larger hole size than the outside diameter of the casing. This is accomplished by using an under reamer behind a smaller diameter pilot PDC bit. iv. Centralization and stabilization No conventional cementing centralizers were found economical and rugged enough to withstand the drilling forces and that could be attached to the casing without altering its performance. Solid centralizers may need to be added to the casing for directional performance, wear management, key seat control and centralization for cementing. Both the issues have been tackled by installing hydro formed stabilizers and wear bands using crimping process. v.

Fluid Requirement Compared to conventional drilling operations, experience has shown that flow rates can be reduced substantially in “casing drilling system”. As annular volume is reduced dramatically, hole cleaning is improved due to higher annular velocities achieved, even with reduced flow rates. Cleaning the hole more efficiently and removing cuttings faster aids in ECD reduction. However, higher annular velocities and the resultant friction losses in the annulus increase the ECD. Each application must be evaluated to determine the balance that must be struck between flow rates to clean the bit face and clear the annulus of cuttings, and ECD management. Once all factors have been considered, the proper flow rate and nozzle configuration can be selected. An inherent benefit of drilling with casing is the “mono bore” annulus. Conventional drilling assemblies result in different annular velocities around each drill string component. This can lead to well bore erosion around drill collars and inefficient cutting transport around the smaller diameter drill pipe. With casing as the drill string, the annular space along the entire well bore is virtually equal allowing the optimum hydraulics to be “dialed in” based on the fluid properties, cuttings concentration and flow rate. Hole cleaning ECD management and hole cleaning are much easier. Hole cleaning has not been an issue on previous wells. While no caliper log data is available, lag time and cement returns do not indicate borehole enlargement to be an issue.

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vi. Fishing It is possible to conduct conventional fishing operations to recover junk from the hole while Casing Drilling. A fishing operation was conducted using conventional tools (mills, junk baskets, magnets, etc). The only difference was that these tools were run in and out of the hole with the wire line, thus making the process faster than having to trip the drill string each time a fishing run was made. The casing may actually be used similar to wash over pipe to assist in the fishing operation. vii. Logging/Formation Evaluation Drilling with casing requires that the well be cased as drilling commences. This prohibits logging the open hole with conventional wire-line logging tools once the hole section is complete unless the casing is pulled above the zone and logged below the bottom. One solution to this problem can be to log while drilling (LWD). Alternatively depending on what type of logs or what interval must be logged, cased hole logs can be run inside the casing or open hole logs can be run out the bottom of the casing to log intervals of interest. Other formation evaluation tools such as core barrels and testing equipment can be adapted to the wire line retrieving tools and then used conventionally once latched into the casing. The technique for running open hole logs that has been found most effective, is to drill to TD with the final casing, release the bit, and then ream back to the previous casing shoe. The logs are then run through the casing just as they would be if the well were drilled conventionally. Once logging is completed, the casing is reamed back to bottom and cemented. This eliminates the need to trip all the way out of the hole and provides a way to continuously circulate the well in case it begins to flow. viii. Cementing and Drilling Out the Shoe In casing drilling, once the casing is drilled to the casing setting depth, the BHA is wire line retrieved. The casing will not have a float collar to land the cement plug. To overcome this problem, the displacement plug must land and latch into the casing and serve as a float. The plug and cement in the shoe joint must then be drilled out with an under reamer and pilot bit assembly connected to the next smaller size of casing. ix. Directional Control A limited amount of directional work with steerable motors for both deviation control and to a planned target has been done with the 7-in. casing during the phase one and two trials. The directional BHAs could be run and retrieved with the wire line without any difficulty. The directional drilling performance was similar to the directional performance experienced when drilling at Lobo with drill pipe.9 x. Well Control Many well control incidents occur while tripping pipe. These well control incidents are avoided with the Casing Drilling process because pipe tripping is eliminated. But some kicks are taken while drilling ahead, and Casing Drilling will not prevent these. xi. Coring Coring operations with casing can be conducted in two different ways: a) The first method involves running conventional core barrel (both inner and outer barrel) and core bit below the DLA and using an under reamer above the core barrel to open the hole to the full dia. Core sample can be taken at any time and drilling can resume with little delay after coring. 283


b)

The second method involves using the bottom joint of casing as the outer barrel and only tripping the inner barrel attached to DLA. This method allows larger core to be taken and also drilling ahead by replacing inner barrel with a drill plug.

2. Drilling with casing (DwC) Weatherford System Drilling with Casing (DwC) technology utilizes the casing string as a drill string so that casing is landed on bottom during the drilling process rather than later in a separate installation process. Many areas of the world have used the practice to drill-in the final tubing string and cement in place with the drill bit still attached. Modern drilling with casing is not limited to only the final string of the well. In fact most modern DwC jobs involve drilling the surface hole and intermediate hole sections. There are two basic technologies used for Drilling with Casing. The first technology employs a bottom hole assembly comprised of a positive displacement motor (PDM), drill bit and hole opener. The assembly is latched to the first joint of casing. As the assembly drills ahead, the casing is lowered into the hole, either in a static or rotated mode. Upon reaching total depth (TD), the latchon bottom hole assembly is recovered with a special retrieval tool. A valve system is run and installed before cementing commences. The second technology utilizes only casing to transmit rotary torque and weight to the drill bit. A drillable drill bit and valve assembly is made up and run with the first joint of casing. The casing string is rotated during drilling, typically with a spear assembly that provides rotation to the casing. Upon reaching TD, the casing can be cemented immediately, with no need for an additional trip. Both the DrillShoe tool and the float collar normally would be made-up to a casing joint. When TD is reached and circulating bottoms-up, cementing can begin immediately, since a float collar is present in the string throughout the drilling operation. The DwC system uses casing as the drill string in a similar manner to a drill bit on drill pipe. Casing is rotated using a top drive, with additional lengths of casing added as the well is being drilled. Once all the required depth has been reached, drilling stops and the assembly is cemented in place. The next drilling assembly–whether conventional or DwC–is run in to drill out the cement. This assembly will drill through the center of the previous DwC system without damage, and carry on drilling as required. Benefits include reduced rig time, operating costs, flat time and operational time, as well as improved and simplified well construction operations. In addition, DwC eliminates hole and casing running problems, improves drilling efficiency by eliminating some flat spots in the drilling curve, improves well bore quality, reduces risk, and the ability to cement almost immediately upon reaching TD. DwC Tools Casing Drive Systems The requirements for turning the casing are identical to those for conventional drilling. The hoisting equipment must hold the weight, apply rotational torque and containpressure. Rotary drilling with casing required a method of connecting the top drive to the casing, to drive the casing string. Extending the depth range required the development of both a fit-for-purpose internal and external grip casing drive system. To maintain acceptable 284


load forces for extended lengths of casing, the slip area of the internal grapples was significantly increased to spread the forces over a larger area. The tool is designed for quickly connecting in the casing to minimize connection time. A stop ring is positioned near the top of the spear to ensure the grapples are engaged in the proper location inside the casing. A simple quarter turn to the right engages the spear to hold the casing string and apply rotational torque. A quarter turn to the left, without axial load, releases the tool. Pumping energizes the packer element. A mud saver valve can be incorporated to minimize spillage on connections. Drilling With Casing Bits The leading component in this stepchange technology is the Weatherford DrillShoe drillable casing bits. Weatherford has introduced a range of proprietary drillable bits for casing drilling applications that are made up directly onto casing.

Shown in both closed (left) and expanded (right) positions, this expandable bit is one of the newest advances in drilling with casing technology. It incorporates many of the features of a standard PDC bit while drilling a 40 percent largaer hole, and is designed to replace a conventional hole opener.

These casing bits have been designed to emulate the standard features of conventional drill bits in a drillable package. DrillShoe I and DrillShoe II have now led to the innovation of a third generation, DrillShoe III. DrillShoe I is designed for drilling very soft to soft unconsolidated rock, typically surface hole, in sizes ranging from 95/8 to 20 inches. Benefits include rapid and damagefree drill out, and suitability for applications with standard buttress or premium casing connections. DrillShoe II is for consolidated formations. Features include PDC cutters along with a proprietary diamond cutting structure, the ability to run on most standard casing and liner drilling systems, and interchangeable drillable nozzles that optimize performance. Sizes range from 5 to 20 inches. The cutting structure’s design in the first two generations is a balance between the need to drill ahead and the requirement for the cutting structure to be subsequently drilled out. DrillShoe III, meanwhile, features a PDC cutting structure mounted on displaceable blades. Once the casing string has been drilled to TD, a ball is dropped that seals off the flow path, resulting in a pressure increase that forces the inner piston downward, displacing the PDC cutting blades into the annulus. Cementing ports on the inner piston are exposed once the blades are completely displaced. It is designed for more competent formations and longer drilling intervals. The thirdgeneration DrillShoe combines the benefits of a PDC cutting structure with the ability to displace its nondrillable cutting structure into the annulus, leaving only drillable materials in the path of the following drill string. 285


Weatherford customers have set more than 400 casing strings with the DwC system in sizes from 51/2 to 20 inches. Drilling with Liners (DwL) Liner drilling systems have been used for penetrating high pressured formations into deeper depleted zones. Liner drilling extends casing points in environments where pressure gradients are increasing with depth. The practice should be considered an alternative for reducing trouble time and reaching objectives in critical, narrow-margin wells. The concept relies on managing annular fluid pressure around the large-diameter liner to create favorable equivalent circulating density (ECD) profiles that allow penetrating farther into narrow pore pressure-fracture gradient windows. However, as liner drilling proceeds beyond normal limits, risks must be managed for making drilling connections, liner cementing and maintaining well control. The approach is consistent with ongoing industry focus on managed-pressure drilling using conventional drill-strings. In this concept, the hole is drilled - with a conventional drillstring - to traditional well control limits, e.g., a kick tolerance limit. The drill-in liner is then run, mud weight is reduced and drilling continues. In some circumstances, this concept may allow significant extra interval to be drilled beyond conventional limits, thus increasing the chances of reaching deeper objectives. Other benefits include reduced stuck pipe consequences and added capability to kill underground blowouts. The liner drilling process results in installation of full-strength tubulars in the well. Liner drilling may also be used prior to reaching conventional casing points to mitigate cyclic fluid losses and fluid gains (ballooning effects) that often plague narrow-margin drilling. Weatherford is the world leader in rotating liner systems, holding records for the longest rotating liner installed (18,233’,) and the heaviest liner run (782,775 lbs.) Applications for Drilling with Liners include: z Depleted formations z Unstable formations z Loss zones z Pressure zones z Salt dome drilling z Moving/swelling formations z Excessive hole cavings Future Developments/Applications z Deep Water Applications z Under Balance Drilling z Use Of CWD With Air Drilling z Use Of Single String Of Casing From Surface To TD z The Ultimate Drilling Solution May Be A Combination Of Casing Drilling With Expandable Tubulars Deep Water Drilling A tight operating window between fracture and formation pressure characterizes most deepwater drilling. The consequence is that as many as seven, eight, or more, casings may be needed to reach deep drilling objectives. Industry has become adept at managing the balance of mud weight, equivalent circulating density (ECD), trip margins, lost circulation material treatments and other operational aspects to try to push the casing points. However, this balance is difficult, and problems occur frequently. 286


Deep Water wells are inherently expensive. However, when problems occur, they can be extensive, and cost overruns commonly approach 50% and more. With the introduction of Casing Drilling lost circulation, stuck pipe and well control issues have all but disappeared on wells. This was an unexpected benefit, but clearly one that has tremendous potential in the deepwater environment. Directional Casing Drilling Vertical wells can sometimes be drilled with casing using a simple system consisting primarily of a special bit attached to the casing that can be drilled out to run subsequent casing strings. But when there is a need to drill with a motor without rotating the casing or the section cannot confidently be drilled with a single bit, then a retrievable drilling assembly that can be recovered and re-run is required. Even some sections that can be drilled with a drill-out bit may be more cost effectively drilled with a retrievable system. A retrievable Casing Drilling system is required for directional wells because of the need to recover the expensive directional drilling and guidance tools, the need to have the capability to replace failed equipment before reaching casing point, and the need for quick and cost effective access to the formations below the casing shoe. Casing Drilling of directional wells provides a practical alternative to drilling the wells conventionally and then running the casing as a separate process. It assures that the casing can be run to TD and it captures many of the savings that have been proven while Casing Drilling vertical wells. For larger sizes of casing, no loss of efficiency occurs while drilling with the steerable tools below the casing. This allows the operator to take full advantage of the faster tripping and trouble avoidance benefits provided by Casing Drilling. Tesco typically pulls the BHA with a wireline unit, but this will require a higher capacity wireline unit when a directional assembly is used in the larger casing sizes. Directional drilling with smaller size casing may sacrifice some drilling efficiency due to the requirement to use smaller motors and is most advantageously applied in situations where the Casing Drilling system provides an enabling technology rather than an improvement in efficiency. Underbalanced and Air Casing Drilling Casing Drilling also seems to have application for drilling in under balanced situations. One of the next goals for the Lobo development is to try to eliminate a string of casing by drilling from surface casing to TD with one string of pipe instead of two. This may be accomplished by drilling with a rotating head so the deeper zones can be drilled with a much lighter mud weight than is currently used. An obvious advantage to under balanced drilling with casing is that the well does not have to be balanced with heavy mud to trip out of the hole to run casin, as would be required with a conventional system. Wells can be drilled with the Casing Drilling system with smaller rigs than are required for conventional drilling. This has a direct advantage in situations where the rig and a conventional drill string must be transported by helicopter. It also may allow smaller rigs that have been left on platforms for repairs and recompletions to be used for sidetracks and infield drilling without needing to bring in a larger rig. There are also potential applications that require a little more development. Equipment to allow the Casing Drilling system to be used while air drilling is under development and modifications to the system to allow it to be used in deep water applications are in progress. The ultimate drilling solution may be a combination of Casing Drilling with expandable tubulars, but there are several hurdles that must be overcome for this to be practical.

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Use Of CWD With Under Balanced Drilling Advantages 1. Safer than UBD with Drill pipe (no tripping of drill string) 2. Can eliminate intermediate strings of casing 3. Drills faster. Result 1. Improved production 2. Reduced time on location 3. Saves money. Use Of CWD With Air Drilling – Advantages 1. Reduced compression demand 2. High annular velocities 3. improved tolerances for water influxes 4. Improved penetration rates 5. Reduced mud ring build up Result 1. Ability to drill deeper on air 2. Use less horse power to drill. Conclusions The conclusion drawn from initial CWD test wells suggest cost savings of 10-15% for trouble free wells. Elimination of unscheduled events encountered in trouble some wells may increase savings up to 30% or higher. Casing Drilling eliminates all the costs associated with these down hole problems: z Swelling Formations z Sloughing Formations z Washouts z Swabbing z Hole in Casing or Key Seats z Running Logs and Casing Casing drilling, an innovative process for simultaneously drilling and casing a well, is emerging as viable technology for the 21st century. Field studies have demonstrated a 20 - 30% reduction in the time required to drill wells from spud to rig release when utilizing casing drilling. 1. As on date it is mainly used for following categories of wellsz Top Hole Sections: Conductor and Surface Casing z Trouble Zones: Drilling Liners z Directional Sections: Intermediate and Production Casing 2. In ONGC, especially in Geleky area of Upper Assam Asset where wells of depth more than 4000m are taking too long for completion due to one or the other problem, this technology can be tried in 2-3 wells to test whether this can reduce cycle time and reduce the cost of drilling . Although cost is slightly on higher side but may helps us in completing our 8 ½” section in 45 days. 288


20.2 EXPANDABLE CASING The fundamental concept of expandable casing is cold-working steel tubulars to the required size downhole. This process, when exactingly controlled, can be mechanically preformed in a down hole environment. Many technical and operational hurdles have to be overcome when using colddrawing processes in a downhole environment. Solid expandable systems are solid steel jointed pipe that are run in the hole as normal casing and expanded downhole to a pre-determined OD and ID. Once the system is expanded, the entire system will withstand expected collapse and yield pressures. Once the solid expandable system is put on depth, an expansion cone, called launcher, which is placed inside the first casing joint, is used to permanently mechanically deform the pipe (fig. 1). The cone is moved through the expandable string by a differential hydraulic pressure across the cone area, by a direct mechanical pull or push force, or by a combination of both. Solid expandable tubular technology provides feasible options for drilling, completion, and workover operations allowing operators to reach previously unattainable target zones. Solid expandable tubular (SET) installations have increased production, extended production life through remediation of existing pay zones, and provided the ability to reach target depths. In a drilling application, solid expandable tubular technology reduces the telescopic effect created by using multiple casing strings in deepwater or extended reach wells, thereby preserving valuable hole size. Deepwater operators, who were the drivers of solid expandable tubular (SET) technology, will be tremendously benefited from this technology. Since its development, the technology has rapidly moved from the deepwater, to a technology that has been embraced by operators in many basins. At present only 22% of the installations have been in deepwater, with over 65% of the total jobs having been done on land. In 1998 an autonomous new company M/s Enventure Global Technology was formed by Shell Technology Ventures Inc. and Halliburton Energy Services to develop and commercialize expandable casing technology. System Detail The differential pressure required for tubular expansion is created by pumping through an innerstring that is connected to the cone. The hydraulic force acts across the bottom side of the cone area forcing it upward. Mechanical force is applied by either raising or lowering the inner-string (fig. 2). The progress of the cone through the expandable tubular string deforms the steel beyond its elastic limit into the plastic region, while keeping stresses below ultimate yield (fig. 3). Expansions greater than 20%, based on the ID of the pipe, have been accomplished in lab. Most applications using 4-1/4 in. to 13-3/8 in. tubulars have required expansions less than 20%. Expandable technology is seen as a means of reducing the overall cost of a well and its support infrastructure. The application of the technology within the first ten years has been aimed mainly at those well bore construction techniques that have remained unchanged for decades. Telescoping casing designs have existed since the very first wells and reservoir completion practices have remained stagnant, dominated by gravel packing. The basic design of liner hangers, packers and through tubing straddles has not changed either; expandable technology will, and already has revolutionized techniques in these areas. Expandable Casing Technology will enable oil and gas operators to access reservoirs that cannot be easily reached with current methods. By expanding casing in situ, the hole size can be maintained and the target reached with minimal well tapering. This results in improved reservoir 289


Fig. 3. Stress/strain curve for solid expandable tubular systems. Fig. 1.

Fig. 2. Differential pressure pumped through the inner-string.

economics by reducing well capital expenditures and improving the success rate of reaching sub salt targets. In addition to rig-time savings and lower well costs, expandable casing technology can result in overall smaller hole size from spud to total depth. Expandable casing offers the potential for a step change in well construction technology. Enventure’s expandable-tubular systems address numerous drilling and completion challenges and can especially enhance deepwater operations, one of the industry’s highest priorities. The choice of comparatively larger final hole sizes that expandable-tubular technology allows can provide access to previously unreachable reservoirs; it can also reduce drilling time and the size of drilling equipment, including lay-down areas and auxiliary equipment required on offshore platforms. In operators’ bottomline terms, expandable-tubular systems should lower overall project costs. Expandable tubular technology has found many applications such as: z Expandable solid casing that allows the construction of a mono-diameter borehole or function as borehole liners that permit the drilling of larger diameter boreholes. z Expandable perforated or slotted pipe for lining the producing zone. z Expandable legs of Level 6 multilateral junctions that permit the drilling of larger-diameter laterals while maintaining pressure integrity with the junction. z Expandables for use as liner hangers. z Expandable liners for repairing casing SET Systems Solid expandable tubular technology has evolved over the past few years from a radical solution for drilling challenges to a logical well construction process. By incorporating expandable systems 290


in the initial well design stage, the downhole tapering effect is reduced or eliminated. Enventure’s SET product line consists of three basic systems: 1) The Expandable Openhole Liner (OHLTM), 2) The Expandable Cased-Hole Liner (CHLTM) and the 3) Expandable Liner Hanger (ELHTM). In addition to the above the technology also includes the following: z openhole cladding system z monodiameter system Openhole Liner Systems The openhole liner system consists of expandable casing strings planned into the well construction to minimize the telescoping effect of the original pre-expandable well designs. Solid expandables minimize well slimming while adding strings for deeper depth. This slimwell application can lower costs by reducing the following: z mud volumes z steel consumption per well z formation cuttings hence less threat of pollution z size of the rig required to drill the well especially in deepwater applications The openhole system can be used as a contingency drilling liner in any well during the drilling phase. Running this drilling liner maintains hole size when an unforeseen geologic anomaly or problem is encountered. These anomalies and problems can include the following: z unstable formation z over- or under-pressured formation z loss circulation z pore pressure/fracture gradient Having to install an unplanned casing string because of an unforeseen geological anomaly will no longer be detrimental to the well. The only limiting factor to achieving the target is temperature and well geometry constraints. Ultra long-reach horizontal wells will be possible where an entire field can be produced from a single drilling pad, platform, or subsea template. Wellbore extensions can be accomplished by using an existing non-producing well. A window can be cut and an expandable system could be run to re-direct the well to another target.This expandable application maintains hole size to allow a larger liner to be run into the pay zone. An example would be to cut a window in a 9-5/8 in. existing casing and run a 7-5/8 x 9-5/8 in. expandable system. Once expanded, this system would allow for a 7-5/8 in. special clearance coupling liner to be run into the producing zone. The window exit installation involved expanding an Openhole Liner System below the window, allowing the operator to maintain hole size to total depth. This capability increases the range of applications for the OHL System in sidetracks in existing casing. Cased-hole Liner System The expandable cased-hole liner system enables operators to repair existing damaged or worn casing for deeper drilling or other contingencies. The system makes it possible to upgrade exploration-grade casing to a sturdier production casing with minimal loss of casing ID.

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Drill Hole

Run Expandable Liner

Condition Mud, Cememt Liner

Latch Plug

Expand Liner

Expand Hanger Joint

Installation sequence for Expandable Openhole Liner System

Running sequence of the Expandable Cased-hole Liner System

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Mill Out Shoe


The cased-hole liner system is mechanically similar to the expandable openhole liner system except that an additional anchor-hanger joint (elastomer section) is located immediately above the launcher assembly. Expanding this system inside existing casing repairs and reinforces the larger casing for completion. The system can be used to shut off perforations in production casing for re-completion or for deepening the well. This expandable system allows for enhanced control of existing injectors and producers by shutting off unwanted gas or water production. The system has also been used to reconnect a severed wellbore due to subsidence from formation movement. Expandable Liner Hanger System The ELH System provides a much simpler and cost effective alternative to complex conventional liner hangers and liner top packers. Enventure’s Expandable Liner Hanger, with no moving parts such as slips, sleeves or O-rings, combines the functional requirements of a liner hanger and liner top seal, while minimizing the need for liner top squeezes. The ELH System simplifies the mechanical and pressure functionality into a single unit, and eliminates possible leaks in the annulus during setting and for the life of the hanger. Additional savings are realized by eliminating the need for a separate trip to install the liner top packer or to test the liner top.

Running sequence of the Expandable Liner Hanger System

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In addition to the above the following products have also been developed by Enventure 1. FlexClad™ System Enventure’s FlexClad System repairs existing casing, isolates perforated sections and provides a gas-tight liner. This system consists of expandable sealing sections called Flex Hangers, conventional API tubulars that act as spacer joints and flush joint connec-tions. The Flex Hangers are separated along the length of the liner using spacer pipe, enabling this system to be used in smaller casing sizes. The FlexClad System differs from Enven-ture’s standard expansion systems in that the liner and connections are not expanded. 2. Openhole Cladding System The openhole cladding system is an expandable string that is run and installed in the open hole to address the following: z isolate an unstable formation z isolate a water flow z shut off water influx in a openhole completion The openhole cladding system installation process is similar to that of the openhole liner with the exception that it is not tied back into the base casing. Elastomers are configured to seal against the formation. The seal efficiency will be a function of the rock properties where it is set. Porosity, permeability, and rock hardness all affect the seal capabilities.

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3. Monodiameter System Monodiameter technology is currently in the final field-testing stage and already generating results that are impressive and revolutionary. This technology consecutively runs the same size expandable casing strings and expands them into each other to achieve the same ID from top to bottom. The monodiameter removes the telescoping effect of pre-expandable well design System Specifications a. Material: Today, standard oilfield tubular steel is used for Solid Expandable Tubulars after it is subjected to a special heat-treating process to increase ductility, which allows the steel to be pushed temporarily into the plastic region during expansion, reduce defect sensitivity and increase fracture toughness. The Solid Expandable Tubulars currently in use are ERW (electric resistance weld) seamed pipe, custom-made by Lone Star Steel to high specifications developed by Enventure. The specifications, particularly for wall thickness variation of the pipe, are much stricter than for typical oilfield tubulars. For example, the American Petroleum Institute allows a 12.5% variation in the wall thickness of standard oilfield tubulars. Depending upon pipe size, Enventure’s requirements allow only a 5% to 7% variation in wall thickness. b. Sizes Available As on date the SET systems are available in following sizesz 13 3/8" X 16" z 11 ¾” X 14 ½” z 9 5/8" X 117/8"OR 11 ¾” z 8 5/8" X 10 ¾” z 7 5/8" X 9 7/8" z 5 ½” X 7 5/8" z 6" X 7 5/8" z 5 ½” X 7" z 4 ¼” X 5 ½” Note: 7 5/8" X 9 5/8" - Means z 7 5/8" is the size ( OD) of SET casing pre expansion and z 9 5/8" is the size (O.D.) of base casing against which SET will be expanded Further 7 5/8" becomes the ID for the next well section after expansion. c. Expansion Ratios: Normal expansion ratios of SET expandable tubulars are in the range of 10-15% but it can be expanded even upto 20-25 % for mono-diameter casings. On expansion the O.D of SET casing increases thereby decreasing (shortening) its length by approx. 4%. This technology has proved its worth in maximizing production through bigger production casings/ strings, well deepenings, reaching deeper depths with higher casing sizes and as a contingency casing for deep water wells where lot of casing strings are required due to narrow margin between pore pressure and fracture pressure. By reducing telescopic nature of wells, many additional benefits are expected in near future z By reducing casing size, BOP and Riser size can be reduced in Deep water wells. This will reduce the rig cost dramatically and so also well cost. z Land rig size will also be reduced thus reducing foot print and emission. z Producing less waste (cuttings) because smaller wells produces up to 50% less cuttings and hence less environment damage. z Less mud chemical cost z Less steel consumption per well 295


Once mono diameter well completion becomes feasible it will further reduce time and cost for well completion by1) Standardization of tools 2) Fewer BHA make up / break out 3) Higher operating efficiency 4) Higher safety since bigger sizes of casing will be avoided and fewer BHA’s to be handled . This technology was successfully used in ONGC, in 2 wells in Mumbai offshore recently(OctDec 2003). In one well it was used to tap deeper oil layer from an existing well and in other as a contingency casing to attain desired production casing size. Based on its performance 30 more wells are being completed using this technology in the year 2006-07. Presently its cost is on the higher side, hence it is more suited in offshore where production rates are higher and well costs are more but it can be hoped that with the passage of time it will become highly cost effective for less producing fields as well. Application of the Expandable Technology Although expandable products are unique, and interesting in concept and installation, they have little value if cost-effective applications cannot be realized from their development. The economics of expandable tubulars must work for the long-term benefit of operators. As costs decline, the impact on all aspects of well operations is expected to increase dramatically. There is a multitude of applications for this technology, including applications for products for optimizing surface facilities, sub-sea equipment as well as sub-surface products. The application of the technology in the subsurface environment has the potential of significantly reducing surface and subsurface costs and increasing the return on investments (ROI) of the operating companies. This technology enables the operator to “reach through” deepwater subsurface environment just under the mud line containing shallow water flow, rubble zones, etc. which require so many casing points. The use of Expandable Openhole Drill Liners in such cases can give the operator several additional strings of casing above those listed in the casing catalogs This will enable them to reach their objectives, and will not require the premature plugging of wells costing millions of dollars. The openhole system can be used as a contingency drilling liner in any well during the drilling phase. Running this drilling liner maintains hole size when an unforeseen geologic anomaly or problem is encountered. These anomalies and problems can include the following: z unstable formation z over- or under-pressured formation z loss circulation z pore pressure/fracture gradient Having to install an unplanned casing string because of an unforeseen geological anomaly will no longer be detrimental to the well. The only limiting factor to achieving the target is temperature and well geometry constraints. Ultra long-reach horizontal wells will be possible where an entire field can be produced from a single drilling pad, platform, or subsea template. Wellbore extensions can be accomplished by using an existing non-producing well. A window can be cut and an expandable system could be run to re-direct the well to another target. This expandable application maintains hole size to allow a larger liner to be run into the pay zone. An example would be to cut a window in a 9-5/8 in. existing casing and run a 7-5/8 x 9-5/8 in. expandable system. Once expanded, this system would allow for a 7-5/8 in. special clearance coupling liner to be run into the producing zone. 296


Discussion of Deepwater Applications Expandable casing technology can provide value in deepwater well engineering operations in two areas: 1. An enabling technology for low drilling margin conditions 2. A cost-effective solution in conjunction with smaller rigs in deepwater As operations move into deeper water, drilling margins (the difference between pore pressure gradient and fracture-pressure gradient) become narrower. This results in more casing strings required to drill to an equivalent depth below the mudline compared to a well drilled in a shallower water depth. In some cases, using conventional casing programs with an 18-3/4 inch BOP stack and a 21inch OD drilling riser, well objectives cannot be reached with a sufficiently large hole size for evaluation and production operations. Figure below illustrates a sample ultra-deep water well, located in more than 5,000 feet of water, that reached its objectives by using a 13-3/8 inch by 16-inch SET system. SET technology can also be used to provide contingency casing deeper in the well.

Ultra-deepwater well using a 13-3/8 inch X 16-inch SET System

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Next-generation SET systems may allow the equivalent of a “monobore” well to be drilled, whereby the same hole size is drilled from surface to TD. A monobore well opens up further costsaving opportunities for an operator by allowing a slim wellbore to be drilled with a small vessel. Figure shows the progression from conventional well construction to slender wells with SET technology and on to monobore well technology.

Well plan utilizing “nested” Openhole Expandable Liners

Limitation 1. Changes in Mechanical Properties Post expansion strength, ductility, impact toughness, collapse, and burst have been studied for selected sizes of pipe and compared to the same values for the pipe as received. It has been found that; z Ultimate tensile strength tends to increase, z Elongation tends to decrease, with expansion— natural results of cold-working the metal. z Hardness and tensile properties of the tested L-80 casing changed after expansion; however, the casing still met API Spec 5CT requirements after 20% expansion. Similar results were obtained with grade K-55. z Expansion changes the Charpy impact toughness of the expandable-tubular material. However, impact toughness at 32°F and higher is still acceptable, with 100% shear fracture in all cases studied, except for that of the K-55 casing. z Expansion decreases the collapse rating of tubular goods, probably a result of the Bauschinger effect. The Bauschinger phenomenon occurs when plastic flow in one direction (expansion) lowers the applied stress at which plastic flow begins in the reverse direction (collapse). 298


2. Cost The cost of using SET technology is at present towards higher side but with increase in number of applications and entry of more companies in production the cost is bound to come down as it has been recognized as a safe, efficient and reliable technology for z Deep waters z Sub salt environments z Depleted reservoirs 3. API casing with very strict controls specification only to be used z At present restricted to two grades of casing only i.e. L-80 and K-55, z Presently Lone Star Steels is the only manufacturer of casing pipes. 4. In case of stuck up Expanding a liner through a differentially stuck section dramatically changes the stress conditions created by the expansion cone in the pipe, it can cause pipe damage and even rupture the expansion face. To reliably expand steel pipe beyond its elastic limit, it is necessary to maintain a displacementcontrolled expansion process, and thus uniform hoop stress distributions on the expansion cone face. If pipe is differentially stuck, this places geometrical constraints on the liner, drill string and bottom hole assembly (BHA). If the magnitude of the differential pressure is small, the drill pipe and expansion cone will free up the stuck pipe and expansion can be continued safely. However, if the pressure differential is large enough, the liner cannot be freed. Geometrical constraints cause severe bending in the BHA and a large additional rotational moment is applied to the expansion cone. This moment causes concentration of hoop stress on the expansion face, loss of displacement control and potential rupture of the liner. Modifications have been done to the standard BHA, which reduce the risk of becoming stuck, free up constrained pipe and/or enable expansion through the stuck interval without causing hoop stress concentration. Operational procedures have been revised to minimize this potential risk. ONGC Experience SDST horizontal well IA#4ZH (Rig Sagar Shakti) On December 8, 2003 ONGC completed the first successful field application of 5 ½” X 7" size solid expandable open hole liner in LIII B layer side tracked horizontal well 1A-4ZH. It was used as an extension of 7" liner base casing from the top of LIII reservoir to the top of B layer (landing point). Directional 6 1/8" pilot hole was drilled with motor& MWD from 1864m (angle 71.5°) to 2105m (angle 88°) up to top of B layer using gel polymer mud system. Enlarged 6 1/8" hole to 7" using 6" x 7" Near Bit Under Reamer (NBR) and watermelon mill (6.2" size) prior to lowering expandable casing. In this phase 8.6 ppg gel polymer mud was used. 51/2 “ X 7” expandable open hole liner (OHL) of 290m length was run down hole through the existing 7" base liner to a depth of 2101 m keeping Elastomer hanger top at 1811m. After cementing, the plug was bumped at a pressure of 2650 psi. The expansion process occurred at propagation pressure of 3700-4000 psi, and maximum 4500 psi when the hanger joint was expanded against 7" base casing. Expansion was performed in about 8 1/2 hrs. 500 m of 6" drain hole with 5"X 6" Bicentric bit, MWD and Motor assembly was drilled from 2101m to 2600m within B layer using non damaging clay free mud. The well flowed @ 686 bopd.

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SET as a “Remedial measure” in SP#8H well (Rig Pride West Virginia) On January 2, 2004 second 5 ½”X 7" Expandable open hole liner (OHL) was safely installed in horizontal development well SP-8H (clamp-on location). The well, which was planned to be completed as a horizontal in A2VII layer ran into unexpected down hole complications. 9 5/8" casing was short landed by 110m above top of LIII reservoir due to tight hole conditions. Conventionally, 9 5/8" casing would have set on LIII top but the held up resulted in premature loss of hole size. The 7" base casing liner had to be set pre-maturely above LIII top instead of A2 VII layer landing point. To remedy the situation. 5 ½”” X 7" Expandable casing was incorporated in the drilling plan as a remedial measure for preserving hole size in order to achieve the desired objective of placing the 6" lateral section within A layer. The directional hole section of 150m length was drilled in Llll reservoir with a 6" x 7" bi centric drill bit from 2351m (Llll top) to 2501m (A2 VII layer landing point). A Clean out trip was made with stabilizer, near bit reamer (NBR) and watermelon mill. 51/2"X 7" Expandable OHL system over an interval of 192 m ranging from 72° to 87.7° angle was run to the depth of 2501m with Elastomer hanger top at 2309 m. The liner was expanded 11.8% in to 7" base casing and open hole in about 4 hrs using Propagation pressure of 4500 to 6000 psi. The post expansion liner length was 185m resulting in 3.7% decreases in the over-all length. Two 6" lateral sections of 400 m each were drilled using bi-centric bit and MWD in A2 VII layer of LIll reservoir. The well flowed at a rate of 1050bopd Recent Trends in Expandables I.

MonoDiameter Technology The ultimate objective of the MonoDiameter System, the next generation of solid expandable tubular (SET) technology that Enventure Global Technology and Shell has developed, is to make possible a well with the same internal casing diameter from surface to total depth. This system will save significant amounts of time and money by reducing flat time during drilling operations, using a smaller BOP stack, and standardizing equipment such as drillstrings and bits as well as casing. Safety will be enhanced because rig crews will not have to handle large diameter casing and drilling

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equipment, and the frequency of changing out drilling equipment and bottomhole assemblies will be minimized. Smaller, less expensive rigs can be used, especially in deep-water in conjunction with smaller riser, helping to dramatically reduce daily rig costs. A well drilled using this system will have no diameter loss with each new liner. This means that regardless of unexpected reservoir challenges, each well drilled can potentially reach its reservoir with a casing size that will enable reservoirs to produce at full potential. Nesting an expandable system inside an already expanded system preserves crucial hole size, which ultimately results in savings on bits, steel, mud and cement, as well as the storage space required for these materials. Offshore, additional savings materialize in onboard drilling vessel storage requirements because a smaller riser can be used. Reducing the amount of drill cuttings decreases the cost of cuttings disposal, a significant cost in offshore operations, especially when drilling with a zero-discharge requirement. Applying SlimWell Technology over a multi-well program can substantially impact the bottom line.

While SlimWell reduces the telescoping effect in traditional well design, the MonoDiameter System eliminates telescoping, allowing operators to slim down the top of the well while increasing the well diameter at TD. A hybrid well is one that features conventional casing for the first three or four strings and then moves to a series of MonoDiameter liners.

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This will be the first step in deepwater, where the customer might run, for example, 36-in., 20in., 13 3/8-in., 11 3/4-in., 9 5/8-in. MonoDiameter, 9 5/8-in. MonoDia-meter, 9 5/8-in. MonoDiameter, and so on, until the objective is reached. This well design could become standard for deepwater, where, say, only two 9 5/8-in. MonoDia-meter liners could be run on a 16,000-ft well, or eight could be run for a 35,000-ft well. II. Expandable tubulars in multilaterals The production and completion advantages of multilateral technology are well documented. As the technology has developed, more of the functionality of a conventional well has been added to the multilateral well. In addition, higher-level junction types have developed a more significant drop in hole size through them. After milling the window and drilling the lateral, the openhole drill liner is installed. With the application of solid expandable tubulars, operators now have the opportunity to complete multilaterals without the need to compromise on hole size. Solid expandable tubular technology is applicable in a variety of multilateral applications and in a wide range of casing sizes. Solid expandable tubulars make it possible to start the well smaller than normal without compromising the casing size at the multilateral junction, reducing well construction costs. With solid expandable tubulars, it may be possible to maintain the same casing size as the mother bore in the lateral, allowing a larger drain hole to be drilled into the pay zone of interest than might be possible with conventional casing string designs.

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The solid expandable tubular system – including casing, anchor hanger joint, and launcher assembly – is run as a single assembly. Once on depth, a dart is dropped while seal and pressure is applied down the drillstring. This creates a pressure chamber in the launcher assembly. In one trip, the casing is expanded from the bottom to the top and the liner is sealed back and hung off in the base casing.

The lateral hole section is then drilled as per the well program using conventional bits and mud motors. The system is pressure tested and the shoe is drilled out. In the case of multilateral wells, the solid expandable tubulars can be run into the lateral hole sections using a whipstock deflection device. III. Installation of SET Systems Through Milled Casing Windows Currently, the performance of solid expandable tubular systems is proven for use in high-angle and horizontal wells, deepwater wells, multiple installations in the same well, situations that require a relatively long expandable casing string, various cementing scenarios, among others. One application of solid expandable tubular systems that was not qualified in the past was a sidetrack through a milled window. However, recent testing and successful field applications proves the viability of using solid expandable tubular systems in these circumstances. This involves the recompletion of wells in which the original wellbore is no longer meeting productivity expectations, or it is identified that optimal drainage could be achieved by having the wellbore in another location of the reservoir. Using solid expandable tubulars in conjunction with side-tracking technology a well can be recompleted as a larger completion through a casing sidetrack. The combination of solid expandable tubular technology and multi-lateral window milling systems was expected allow operators to slim their wells resulting in a reduced capital outlay, minimized environmental impact, maximized reservoir potential, and create a superior rate of return over conventional development scenarios. Now that it has been proven that these two technologies can be successfully deployed, the value-proposition of making use of existing capitalized assets and a reduced AFE combined with better reservoir dynamics can create a enhanced economic model over conventional applications Solid expandable tubulars are quickly becoming a viable means to overcome certain challenges existing operations face and to offset some of the higher expense by employing its unique technology in existing wells. For the early part of its development, solid expandable tubular technology could not feasibly enter side-tracked wells because of the potential damage sustained during run-in, reducing the reliability of the expansion process. 304


With over 209 successful installations in the past four years, solid expandable tubular technology has established itself as a viable drilling solution and process. This technology continues to provide solutions to drilling and recompletion challenges in both conventional and deepwater wells. It is also quickly gaining a reputation as a proven drilling design technology. Drilling in formations and at depths once thought too expensive is becoming technically and operationally feasible. Each solid expandable tubular installation leads to technological advancements and enhancements that maximize hole conservation while minimizing well costs. Recent technological breakthroughs—developing and deploying a modification on the expandable tubulars and making use of the latest advances in multi-lateral window milling systems—have now enabled solid expandable tubulars to become a reliable and repeatable method to overcome the unique challenges faced by older operations. A lab test, two surface simulations, a field trial, and five commercial installations have all demonstrated that solid expandable tubulars can be deployed successfully in casing sidetracked wells. The combination of solid expandable tubular technology and multi-lateral window milling systems is expected to allow operators to slim their wells resulting in a reduced capital outlay, minimized environmental impact, maximized reservoir potential, and create a superior rate of return over conventional development scenarios. Now that it has been proved that these two technologies can be successfully deployed, the value-proposition of making use of existing capitalized assets and a reduced AFE combined with better reservoir dynamics can create a enhanced economic model over conventional applications. The most obvious advantage is larger ID in the target zone, thereby increasing production. But more importantly, these two complimentary applications have the potential to reduce significantly an operator’s capital expenditures for the life of a field. These savings are realized in the dramatic productivity enhancements made possible by solid expandable tubular technology in fields where the operator has already capitalized the exploration and development outlay. Slowly but surely the scope of expandable tubular technology is expanding to applications like mono-diameter wells, extended reach wells, horizontal and multi-lateral wells etc.

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20.3 COIL TUBING DRILLING Coiled tubing describes continuous lengths of small-diameter steel pipe, related surface equipment and associated workover, drilling and well-completion techniques. Coiled tubing is spooled onto a reel for storage and transport. These strings can be 31,000 ft [9,450 m] long or more, depending on reel size and tube diameters, which range from 1 to 41D 2 in. A hydraulic power pack, or prime mover, controlled from a console in a central control cabin drives the injector head to deploy and retrieve coiled tubing. The large storage reel also applies back-tension on the tubing. The continuous tubing passes over a gooseneck and through an injector head before insertion into a wellbore through well-control equipment that typically consists of a stuffing box, or packoff, riser and blowout preventer (BOP) stack on top of the wellhead. This process is reversed to retrieve and spool coiled tubing back onto the reel. Modern CT equipment and techniques have several advantages over conventional drilling, workover and snubbing units. These include quick mobilization and lower cost, expedited operations with no need to stop and connect tubing joints, and reasonably high load capacities for deeper vertical and high-angle reach compared with wireline and slickline. The flexibility of working under pressure in “live” wells without killing a well and the unique capability to pump fluids at any time regardless of position in a well or direction of travel are also advantages. Coring can be done with coiled tubing using small diameter, single, double or triple tube core barrels such as are used in mineral exploration or engineering geology site investigation. COILED TUBING DRILLING EQUIPMENTS Coiled tubing drilling equipments are widely divided into two categories: 1. Surface Equipments 2. Downhole Equipments 1. Surface Equipments Coiled tubing drilling surface equipments are as follows: i. Coiled tubing drilling unit and associated coiled tubing handling equipments ii. Well control system iii. Circulating fluid and system.

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i.

Coiled tubing drilling unit and associated coiled tubing handling equipments The coiled tubing unit is a portable, hydraulically powered service system designed to run and retrieve a continuous coiled tubing string. The predominant design of coiled tubing unit uses the vertical, contra-rotating chain-drive injector head. The basic coiled tubing drilling unit components are as follows: a. Tubing injector head b. Coiled tubing reel c. Hydraulic power unit d. Control console a) Tubing Injector Head

The CT injector head provides the power and traction necessary to run and retrieve the CT string into and out of the wellbore. Several hydraulic systems are used to enable the CT unit (CTU) operator to exercise a high degree of control over any CT string movement – an important feature in delicate CTD operations where WOB must be carefully controlled. Tubing injector heads are designed to perform three basic functions: • Provide the thrust to snub tubing into the well against pressure as to overcome well bore friction. • Control the rate of tubing entry into the well under various well conditions. • Support the full suspended tubing weight and accelerate it to operating sped when extracting it from the well. The tubing can be snubbed or run open ended, or can be used to convey downhole tools and devices attached to end of tubing. The tubing injector head manipulates the continuous tubing string utilizing two opposed sprocket-drive traction chains, which are powered by contra-rotating hydraulic motors. These chains are fabricated with inter-locking saddle blocks mounted between the chain links and machined to fit the Coiled Tubing string circumference. The saddle blocks within the chain are forced onto the pipe by a series of hydraulically attached compression rollers that impact the force required to establish the friction drive system. The injector head is also equipped with an arch roller system, called a tubing guide, which is mounted directly above the drive sprockets and used to receive Coiled Tubing from the reel and 307


guide it into the chain blocks. At the injector head base, a hydraulically- operated stuffing box is positioned along the coiled tubing centerline and is secured in the chain drive assembly. The stuffing box or “stripper rubber” contains a split elastomer element that is compressed against the tubing. This isolates annular well bore pressure from the atmosphere. The minimum stuffing box working pressure rating is 5000 psig, but it is generally designed for working success upto 10,000 psig. The injector head is supported above the well head in one of the two ways. Either telescopic legs or a hydraulically elevated steel frame commonly called a “jack stand” are used. b. Coiled Tubing Reel It consists of a fabricated steel spool drum with a core diameter of 60"-72" and a 9’ flange diameter side. The basic spool can store up to 26,000 feet of 1.00" OD tubing or 22,000 feet of 1.25" OD tubing. Tubing spooling capacity is dependent on the core diameter. The innermost tubing end is connected through the hollow end of the reel shaft to a high pressurerotating joint. The rotating joint is secured to a stationary piping section connected to fluid pumping system to circulate fluid. One 10,000 psig shut-off valve is provided between the tubing and reel shaft to isolate the tubing from the surface pump lines. The reel rotation is controlled by a hydraulic motor that is used for constant, steady pull and making sure that the coil is being tightly spooled onto the drum. Motor is mounted for direct drive on the reel shaft or operated by a chain-sprocket drive assembly. During lowering of the tubing, slight back-pressure is always maintained on the reel motor to allow the injector head to pull the tubing off the reel and keep tension between the injector and the reel. On the other hand, tubing retrieval pressure increases on the reel motor allowing reel rotation to keep up with the tubing extraction rate out of the well. The primary function of the reel brake is to stop drum rotation if the tubing accidentally parts between the reel and the injector head. The braking system is not intended to halt uncontrolled tubing dispensing but only to offer resistance and slow down reel motion. New reel units have a back-pressure device braking system to slow the reel and also a friction pad braking system for extra control. The friction pad is applied hydraulically to the outer reel flange diameter to slow reel motion. c. Hydraulic Power Drive Units Hydraulic Power Drive Units are sized to operate all of the coiled tubing unit components. The prime mover assembly size will depend on hydraulic-drive unit needs. The prime mover for a specific coiled tubing unit may range from a power take-off assembly (Bobtail land unit design) to a selfcontained offshore skid package. Standard prime movers packages on most coiled tubing units are equipped with diesel engines and hydraulic pumps. d. Control Console Normally all controls are positioned on one remote console. It may be skid-mounted for offshore use or permanently mounted on land units. The console includes all of the controls and gauges required to operate and monitor the coiled tubing drilling unit components. Reel and injector head motors are activated from the control panel through valves that determine the tubing motion direction and operating speed. Control systems to regulate the drive chain, stripper rubber and blow out preventor stacks are also located on the control console. ii. Well control system/ Blow Out Preventer Stacks Coiled tubing drilling requires two sets of different blow out preventer stacks assemblies:

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a. For Bottom Hole Assemblies b. For coiled tubing a) Bottom Hole Assemblies Blow Out Preventer Stacks This consists of annular preventer, blind rams, pipe rams suitable for bottom hole assemblies and drilling spool with isolation valves. The return line is used to circulate out the kick or for taking returns out in drilling an under balanced well. b) Coiled Tubing Blow Out Preventer Stacks The BOP system is a critical part of coiled tubing drilling units. It is composed of four hydraulically-operated rams, generally rated for a minimum working pressure of 10,000 psig. The four BOP compartments are equipped from top down with Blind Rams, Tubing Shear rams, Slip Rams and Pipe Rams. •

Blind Rams Blind rams are used to seal the well at the surface when well control is lost. Blind rams seal when elastomer elements are compressed against each other. •

Tubing Shear Rams Tubing Shear rams are used to mechanically break the coiled tubing in the event coiled tubing becomes stuck or when it is necessary to cut the tubing and remove surface equipments from the well. As shear plates close on the tube, mechanical forces yield the tube body to failure. •

Slip Rams Slip Rams are equipped with uni-directional teeth that move against the tubing when activated to support the pipe weight. In addition, slip rams can be used to secure the pipe by closing on the tube to prevent the movement in the case of high pressure that may blow the tubing out of the well. Slip Rams are fitted with guide sleeves that properly center the tubing in the ram body‘s grooved recess as slips are closed. •

Pipe Rams or Stripping Rams Pipe Rams or Stripping Rams are fitted with preformed elastomer seals that fit the specific OD of the tubing in use. When closed against the tubing, they isolate well bore annulus pressure below the rams. These rams are also outfitted with guide sleeves to center the tubing as the rams are closed. iii. Circulating Fluid and System The bore of coiled tubing drilling equipments is very less as compared to conventional drilling and it results in high frictional pressure losses. Drilling fluid design must give due consideration to the following three points: • Minimizing the frictional pressure losses • Producing more HHP to run the mud motors • Have sufficient density to maintain bore hole pressure and ability to sweep hole clean of cuttings. Low solids mud system is better suited for this. Coiled tubing drilling circulating system is identical to conventional drilling circulation system. It also requires mud tanks, shale shakers, desanders, desilters and centrifuges. But the mud system capacity requirement is less in comparison as smaller sizes of holes are drilled. Typical pressure and capacity requirements for circulation are in the range of 4,000-5,000 psi and 170 gpm. Triplex Pumps (500 HHP) are suitable to meet this requirement. 309


iv. Downhole Tools Coiled tubing drilling gained momentum and acceptance with the innovative work done on downhole tools and bottom hole assemblies to meet the needs of deepening, re-entries and horizontal wells. Coiled tubing drilling downhole tools are as follows: a. Drill bits b. Positive displacement motors (PDM) c. Drill collars d. Coiled tubing adapters e. Disconnect tools f. Orienting tools Drill bits, PDM motors, drill collars and survey tools are borrowed from conventional drilling operations. Coiled tubing adapters, disconnect tools and orienting tools are unique to coiled tubing drilling. These specialized tools have been designed of necessity. a. Drill Bits Bits used for coiled tubing drilling should be able to attain adequate penetration rates with relatively less weight on bit and high rotational speeds. For directional applications, bits with low torque requirements should be selected to minimize the complications of reactive torque while maintaining the desired well trajectory. b. Positive Displacement Motors Positive Displacement Motors are used to turn the bit. PDM are available for coiled tubing drilling in diameters ranging from 2.375" to 6.5" OD as follows: • High-speed, low torque • Medium speed, medium torque • Low speed, high-torque Motors should be matched to the bits they will be used with. High-speed, low torque motors are suitable for those with TSD or natural diamond bits. Medium speed, medium torque motors are suitable for PDC bits. c. Drill Collars Drill collars provide sufficient weight to the bit to achieve acceptable rates of penetration and also provide adequate strength to enable the BHA to be run in compression. When MWD or steering tools are used, non-magnetic drill collars are used to prevent magnetic interference with these devices. Drill collars should have large enough ID to allow the insertion of the steering tools or MWD system and minimize the pressure drop through the drill collar string adjacent to the survey tool. Non-standard size drill collars may be used. d. Coiled Tubing Adapter Coiled tubing adapter is required to connect the coiled tubing to the BHA. It must be able to resist the torque developed by the mud motor. Mud motors in the sizes suitable for coiled tubing drilling can develop torque in excess of 1,000 ft-lbs in a stall situation. e. Disconnect Tool Disconnect Tool provides a means of disconnecting the coiled tubing from the bottom hole assembly in case the bit or drill collars become stuck. Disconnect mechanisms are of two typespressure release or shear release. Disconnect tools have to resist the torque developed by the mud 310


motors. Pressure release disconnects are actuated by pumping a soft ball through the coiled tubing. Shear release tools are actuated by pulling on the coiled tubing until sufficient tension is applied to shear out pins holding the tool together and disconnect the BHA from the coiled tubing. After the coiled tubing is released, fishing tools can be run to recover the BHA. If the electric line is used, the disconnect mechanism must be designed to accommodate the wire line without interfering with the releasing operation of the tool. f.

Orienting Tools A downhole rotator or orienting tool is required to alter the tool face orientation to control the direction of the hole in directional and horizontal drilling. Orientation tools are actuated by mechanical reciprocation, pressure cycling, torque from the drilling motor, downhole electric motors or a combination of these actions. The tool is run above the mule shoe sub in the BHA. Orientation tools either allow for continuous adjustment or tool face orientation over a fixed range of rotation or for indexed tool face rotation with no limit on the total range of adjustment available. CTD Applications New Wells CTD units can handle small and shallow new wells, typically 1500-1800 metres deep, with hole diameters up to 8 ½”. In some softer operations the hole size may reach 12-1/4" however, the casing size will be limited to a final production casing of 3-1/2". Recent technical advances continue to push these limits. CTD is effective for new shallow gas relief wells being drilled in Indonesia and Venezuela. The small amount of equipment placed to risk, as well as the advantages of personal safety, supports the use of CTD. Many of today’s new well projects, however, are not especially suited to CTD, mainly because of current market economics. In many regions of the world, the relatively new CTD unit and its bulk of required ancillary equipment must compete against a depreciated drilling rig. In these areas, the CTD unit is not an economic alternative to the conventional rig. CTD however provides environmental advantages like small footprint, reduced environmental impact, location remoteness and limited space on offshore platforms. Conventional Re-entry Deepening and sidetracking wells cover the bulk of the conventional re-entry market, and CTD is suited to a portion of these operations. For sidetracks, a whipstock is set at the kick-off depth, and a window is milled in the casing. In such types of wells CTD has limitations of maximum hole size (6") and build up rates (>30 degree/100 ft). For horizontal sidetracks the drain hole length is limited by the required WOB. Here too CTD units have to compete with depreciated drilling rigs with low day rate. Here too CTD has the same environmental advantages as for new wells. CTD is also useful for offshore where UBD is required due to depleted reservoir pressures. Through-tubing Re-entry Other than UBD applications of CTD, the most technically and economically successful applications of CT are in through-tubing reentries. Through-tubing reentries are typically drilled to deepen or sidetrack a well and are performed without removing the well’s production tubing. These projects are suited to CT because no additional equipment is needed to pull the tubing. CTU can move in, rig up, and begin drilling within hours. This quick rig up is especially attractive in offshore and artic locations, where drilling and workover rigs have higher day rates. Here too there are limitations

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in production tubing and hole sizes. For directional drilling, the bottom hole tools limit the applications. Combined with UBD, through-tubing reentry drilling projects provide for the highest potential cost savings for the operator. Underbalanced Drilling (UBD) In true UBD, the well flows while the hole is drilled. The well is not killed while pipe is tripped. This underbalanced condition prevents drilling fluid from entering and damaging the producing formation. This drilling technique is possible with jointed pipe, such as with snubbing units, but it has proven safer and more efficient with CT where the sealing is provided in the injector. Underbalance drilling can be applied in combination with any other application (shallow wells, conventional or through-tubing reentries). The only limitations are those associated with one of these three applications. Sidetracking Technology for Coiled Tubing Drilling. CTD has been used increasingly in recent years for extending existing wells (re-entries and multi-laterals). Through-tubing drilling is a major application for CT drilling. The motivation driving through-tubing drilling is low cost rigless re-entry when overbalanced and safe drilling with Christmas tree and tubing in place when under balanced (for reduced formation damage). In addition the case of drilling 4-3/4" and smaller boreholes with the CT is an advantage in a region that does not have an established practice of slim hole drilling. The key enabling technology for viable through-tubing drilling is the ability to sidetrack in casing below the tubing tail. With the advent of CT drilling, the option of through-tubing drilling has become a reality and the following through-tubing sidetracking techniques are available for circumventing a production problem. a. Cementing sidetracking (CS) b. Whipstock in cement (WIC) c. Through-tubing whipstock (TTW) a. Cement Sidetracking (CS) This technique is the most straight forward. It consists of placing a specially designed cement plug in the casing and drilling with a bent housing motor to cut the window and lateral. The advantages of this technique include that no iron is left in the well (the cement can easily be drilled out if necessary at a later date) and there are few opportunities for something mechanical to malfunction. If the existing wellbore must be plugged and abandoned, the cement kickoff plug may be effectively free, making this the most economical technique. The disadvantages of this technique are the short windows, technique sensitivity, and the relatively fragile cement ramp. Because the whipstock is cement, all subsequent operations through the window must be made carefully and preferably without rotation. This technique has been successfully used for 3-¾” and 4-½” hole sidetracks in both 7" and 9-5/8" casing at deviations from 110 to 900. Two techniques have been used to initiate cement sidetracks. If the pilot hole and the exit are on the same side of the casing, the technique is referred to as a CSS (cement sidetrack same side). If the pilot hole is on one side of the casing and the BHA is then oriented to drill toward the opposite side of the casing, the technique is called CSO (cement sidetrack opposite sides). The CSS technique has the advantage of direct application of full BHA elastic load at a known depth. The CSO technique has the advantage that the mill hits the casing with an angle of attack, and hence is required to cut less casing (for the same dogleg severity), and also the cement is much thicker at the top of the window. 312


b. Whipstock in Cement (WIC) This technique is slightly more complicated than the CS technique. The casing is filled with cement (preferably to the tailpipe) and a through-tubing directional assembly is used to drill a hole to the inside of the casing at the proper tool face angle. Enough straight hole is drilled adjacent to the casing to make a straight rathole for the whipstock. The procedure described above can be used if the well is theoretically deviated more than 30 at the point where the whipstock is to be set. From a practical stand point, a hole deviation of more than 100 may be required for stable tool face readings while drilling (this applies to the CS technique also). A bottom trip whipstock is run in with a bottom hole assembly (BHA) of; a. whipstock b. starter mill c. steering tool d. CT c. Through-Tubing whipstock TTW). Several versions of through-tubing whipstock exist. All consist of an anchor that reacts torsional and axial loads and are designed to allow the small through-tubing diameter to span from the high side to the low side of the much larger casing inside diameter. All TTW are normally used for a near high side exit. This is to allow gravity to force the upper whipstock taper to lay against the low side of the casing. Coil Tubing Under balanced Drilling – Challenges •

Rigs In the early 1990’s when directional Coiled Tubing Under balanced Drilling first entered the market, conventional Coiled Tubing units were utilized with modified substructures and cranes supporting the injector over the well head. The main draw back to these units was the size and length of coil they could facilitate. As the benefits and rewards of Coiled Tubing Under balanced Drilling grew, so did the Coiled Tubing drilling rigs. •

Tools Coiled Tubing Under balanced Drilling tools have always offered a challenge to provide reliable, trouble free operation but this can usually be attributed to their small size and extreme conditions that they are exposed to while drilling under balanced. Major improvement to bottom hole assembly (BHA) and motor design has generated tools that rarely malfunction in their basic componentry. Additional instrumentation such as internal /external pressure and temperature, weight on bit (WOB) Measurement, gama ray and resistivity readouts have been introduced to the BHA through real time signals that only CTUD can supply. Motor life is a key issue with Coiled Tubing Under balanced Drilling. Due to the inability to rotate the tubing in the hole, drilling of the formation relies on bit rotation alone. When high volumes of gas are pumped through these motors the gas impregnates and swells the stator rubber, decreasing the torque out put to the bit and resulting in excessive motor trips. •

Coil Coil manufacturers have been able to meet the demands of the industry to develop tubing specifically designed for drilling. The typical diameters are concentrated around 60.3 mm and 73.0 mm. Some contractors have opted to utilize pipe size like 66.7 mm, 82.6 mm and 88.9 mm in order to gain minimum bulking/reduced annular space advantage. With larger Coiled Tubing Drilling rigs for Under balanced drilling available in the market, coil wall thickness has increased dramatically along with yield strengths to try and extract as much fatigue life as possible out of each string of 313


tubing. Jointed drill pipe is available in various diameters and weights and has a distinct advantage over coil by replacing any section of the string when required. Butt-welding of the coil through experience, technique and material, has seen vast improvements but still creates a high fatigue area in the drill string. •

Standby Time One of the largest contributors to high Coiled Tubing Under balanced Drilling prices is “stand by time”, especially when daily costs of a multitude of services are already quite high, Coiled Tubing Under balanced Drilling can usually be split up into three main services: • Coiled Tubing and pumping • Production testing equipment • Directional services This separation can prove to be costly. If one of the services has problems the rest continue to keep charging. •

Engineering One of the most critical aspects involved with Coiled Tubing Under balanced Drilling operations is the preplanning of the job by all parties involved. Drag and buckling analysis, circulation analysis, hole sizing depths fluids and BOP are typically referred to by Coil Company. Well bore trajectory reservoir lithology, tool sizing, and boundary restrictions are planned by directional services. Reservoir fluids/gasses, pressures and flow rates are analyzed by the production testing company. Contingency plans are always necessary while drilling under balanced with Coiled Tubing. •

Integration of Coiled Tubing Under Balanced Drilling If Coiled Tubing Under Balanced Drilling is thought to be advantageous, the equipment and tools have been proven and the well bore configuration is conducive to utilizing coil, then the final step towards creating an economically effective operations is to integrate the services involved. By combining all related services into one, rather than incorporating the necessary services available through one company, the experiences level will increase, risk will decrease and cost will be predictable. Since Coiled Tubing has typically been implemented as a live well intervention tool, this technology has always been linked with under balanced drilling. Proper candidate selection and job planning is critical to the success of under balanced drilling jobs. There are numerous issues to consider when contemplating an under balanced drilling project. Many of these issues are common to both jointed pipe and joint less pipe (i.e. Coiled Tubing) drilling operations. One of the major issues associated with under balanced drilling is that of borehole stability. Many of the growing number of candidates for under balanced drilling exist in depleted, or under pressured reservoirs where under balanced drilling serves to alleviate many of the drilling problems associated with overbalanced drilling. These include massive losses of circulation and differential sticking. •

Rate of Penetration Optimizing rate of penetration with Coiled Tubing must be achieved with limited weight on bit. It is important to keep in mind that Coiled Tubing is plastically stressed and due to absence of connection, it can safely be used in compression. By comparison, jointed pipe operations utilize 314


drill collars further down in the string (usually near the bottom of the vertical section) to provide weight and maintain the drill pipe in tension. The weight of the Coiled Tubing or combination of the Coiled Tubing weight with injector force wills more than make up for the lack of drill collars. However, due to the helical nature of Coiled Tubing and the inability to rotate friction is increased resulting in the reduction of the effective transfer of weight to bit. The available weight on bit also does not increase with increased depth. The additional weight of Coiled Tubing due to increasing depth is taken up in friction due to helical buckling in the vertical well bore. Typically, rate of penetration with Coiled Tubing is controlled by motor/bit selection and the reduction of hydrostatic pressure on the formation (i.e. under balanced drilling) •

Hole Cleaning Optimizing hole cleaning parameters with Coiled Tubing and multi-phase flow is not a well understood science especially in highly deviated or horizontal wells. In general, it is felt that foam is superior to nitrified fluid (more susceptible to slugging) for cuttings removal. As a general rule of thumbs foam qualities around 80% are preferred to minimize cuttings beds in the horizontal well bore and build section. By comparison experience with non-foamed multi-phase flow has experienced success with qualities around 60% or less. Where effective hole cleaning can be achieved with non-foamed or nitrified fluids, this system is usually simpler to manage. Foam, typically has higher friction and this can limit the ability to reduce bottom hole pressure, however good, stable foam will be more homogeneous and make cuttings transport more predictable. •

Bottom Hole Pressure Bottom hole pressure is a function of nitrogen to liquid ratio in either case; reduction in bottom hole pressure below reservoir pressure can sometimes stimulate influx of reservoir fluids. This influx will affect the bottom hole pressure depending upon the nature of the influx (gas, oil or water) and the rate of influx. Liquid in flux will tend to be self-regulating in under pressure formations while gas influx can often result in significant unloading of the well bore. •

Cost Cost, of course, is the driving parameter behind most oilfield operations. However, it is more prudent to consider value than to focus strictly on costs of individual items in a reservoir management scheme. For example while increasing nitrogen rates may result in higher nitrogen cost per unit time, resultant increased penetration rates or improved hole cleaning leads to reduced risk of stuck pipe and reduced wiper trips. Coiled Tubing Horizontal Drilling Coiled tubing drilling for horizontal wells requires the following special purpose tools: 1. A downhole surveying tool 2. Bent sub 3. An adjustable bent housing on PDM. 4. A downhole orientating sub-assembly which allows proper tool face orientation during directional drilling. Research and developments which have specifically led to the coil being successful for horizontal drilling are:a. Thrusters which allow higher weight to be placed on the bit in the horizontal section. b. Torque reactors which compensate for the reactive torque from the drilling process. c. Rotators which give one option of rotating the BHA to overcome drag friction which has limited the length of horizontal wells achievable with cost. 315


Coiled Tubing Life Failure of coil tubing is mainly due to the repeated bending and plastic deformation of coil tubing on and off the reel and gooseneck during Coiled Tubing drilling operations. CT Failure Causes Statistical analysis of CT failure causes are as follows: 1. Corrosion 51% 2. Overload 21% 3. Mechanical damage 12% 4. Manufacturing defects 07% Though the mechanism for predicting Coiled Tubing life is not fully understood, still it has been possible to predict very closely actual life performance. Coiled tube working life is affected by Coiled Tubing size and thickness, internal pressure, yield strength, reel diameter, gooseneck radius, operating conditions (corrosion etc.). Based on scientific studies carried out, it shows that Coiled Tubing life can be greatly increased by increasing Coiled Tubing wall thickness and Coiled Tubing strength, while the Coiled Tubing working life decreases under high internal pressure, corrosion, butt weld conditions etc. It can be seen that; 1. 2. 3. 4. 5. 6.

CT life increases with smaller OD of CT CT life increases with higher wall thickness CT life increases with higher yield strength. CT life increases with increase in reel diameter and gooseneck radius. CT life reduces with increase in internal pressure. CT life reduces with corrosion and after operating conditions.

CT Metallurgy Precision Tube Technology, Quality Tubing Incorporation and South Western Pipe Inc. are the major manufacturers of these coils. The steel used for making coils is mainly High Strength Low Alloy Steel (HSLA). A typical steel composition of A606 alloy type 4 modified is as follows: Composition Carbon 0.1-0.15 Manganese-0.6-0.9 Phosphorus-0.030 max. Sulphur- 0.005 max Silicone 0.3-0.5 Chromium-0.55-0.70 Copper-0.2-0.4 Nickel-0.25 max Physical Properties Minimum yield strength 70 ksi Minimum tensile strength 80 ksi Minimum Elongation 30 % Maximum Hardness 22C Rockwell Capabilities (Advantages) Of CTD a) Fast trips A primary consideration of CTD is that the pipe is continuous, and does not require the makeup of connections during operations. This feature allows for faster handling and tripping speeds that can contribute to reduced costs. 316


b) Drill and trip underbalance Coiled tubing systems have been designed to operate under live-well conditions and have a commendable safety record in performing this type of work. Traditional drilling practices include using the drilling fluid as a pressure control system (first line of defense). Coiled tubing systems, alternatively, have first and second lines of defense in their stripper rubbers and BOP systems that render the need to have weighted drilling fluids redundant. Both drilling and tripping can occur while the well is under pressure. c) Small footprint The coiled tubing drilling unit is significantly smaller than a conventional drilling unit requiring less wellsite preparation and is very suitable for urban areas, remote offshore/land locations and other locations where land availability and environmental impact is of great importance. d) Direct control and Monitoring The continuity of coiled tubing merits use of electric wire line in the tubing that facilitates continuous, high quality two-way telemetry between surface and downhole for real time data and control. e) Considerable safety advantages • Closed system permits continuous well control even when tripping. • Quicker shut-in in emergency situation. • Easier to handle a kick. • Wellbore isolated from atmosphere any time that is desirable. • No personnel needed near the wellhead during most operations, including trips. f)

Reduced environmental impact CTD operations generate less noise and fewer emissions. Smaller diameter wells generate smaller volumes of cuttings. g) Portability As coiled tubing drilling does not require a mast, rotary table etc., the equipment required for CTD is much smaller than for a conventional rig. Hence mobilization, rig up and rig down are faster. h) Continuous circulation The circulation system in CTD operations is so complete such that circulation can continue even while the trip is taking place. i)

Slim hole capabilities With larger diameters coiled tubing now available, coiled tubing can be used to drill or core slim holes. Further the operator can opt to complete the well with coiled tubing in place, thus eliminating the casing. Slim hole technology can further be applied to; • Vertical deepening • Small cased, wellbore re-entries • Short radius re-entries. • Horizontal drilling with coiled tubing. Limitations Of CTD a) Annular Velocity for cuttings removal Sufficient annular velocity is required for removal of drilled cuttings. However, it is limited by three factors: • Coiled tubing pressure losses. 317


• •

Flow rate for downhole motor. Flow rate for MWD.

b) Downhole weight on Bit (DWOB) WOB is critical at the end of the build section and at TD. The bending friction force in the curved section affects the DWOB and consequently the maximum reach. Coiled tubing OD and wall thickness have significant effect on reach. WOB of 100 lbs per square inch of bit diameter is required to achieve practical ROP. Helical buckling of coiled tubing in the 9 5/8" casing will increase the friction forces and thus reduce the weight that can be applied on the bit. If coiled tubing is run inside 7" casing or smaller, relatively more DOWB can be supplied to the bit. c) High Circulating Pressures Friction losses in the coiled tubing results in higher circulating Pressure and tend to limit the flow rate and hence effects the selection of mud motor. Well-designed drilling fluid properties should help in decreasing friction losses without sacrificing carrying capacity. d) Tension The maximum allowable tension depends on the pipe OD, ID and the fluid strength of the pipe. e) Torque The maximum stall torque of the drilling motor will impact the selection of coiled tubing pipe. The stall torque depends on the flow rate th rough the motor. If the pump rate is reduced, the stall torque is also reduced. f)

Short Coiled tubing Life One to two wells can be drilled with the same reel, depending on the drilling depth and problems encountered while drilling. Number of cycles over the gooseneck, in addition to depth and pressure should be closely monitored to determine if the CT reel can drill a second well. Heavy wall pipe and high yield strength improve the CT life. g) Weight and size limits. In order to do larger jobs, it may be required to take multi reels to location, weld or connect the coiled tubing on site and spool it on a larger work reel. However, the cost will be considerably high. h) Limited Reach The amount of the reservoir drained is generally a function of the length of the horizontal section. The reach of the coiled tubing is limited by the limitations in the amount of weight transmitted to the bit. i)

No rotation from surface The inability to rotate the coiled tubing from the surface makes directional drilling more difficult, increase the possibility of sticking, inhibits cutting removal and increases pipe drag. Frequent wiper trips are required to compensate for this absence of pipe rotation. j)

Limited fishing capabilities Due to the very small clearance especially in slimholes and re-entry drilling, availability of reliable fishing tools is a major concern.Thus in many cases stuck ups requiring fishing cannot be liquidated and often results in repeat sidetracking or abandonment. 318


k) High cost of operations CTD operations for normal wells are costlier than conventional rig operations. Techno-Economic Feasibility There are many factors that go into determining both the technical and economical feasibility of CTD candidates. Of these factors which influence the economic feasibility, some tend to increase the competitiveness of CTD while some tend to reduce it relative to other possible solutions. These economic parameters include; the number of wells to be taken up, production benefits from drilling underbalance and possible reduced cost of through-tubing operations. Technical feasibility While advances in CT services have tremendously increased its usage, limitations still exist. This is especially true for drilling projects, where the CT equipment is very small when compared with a conventional drilling rig. A thorough review is required to ensure that the CT is capable of performing the tasks that are required of it to drill. To optimize drilling, the operator must optimize the rate of penetration, trip time and hole cleaning. However, the size of the pipe introduces a number of constraints on the operator when drilling with CT. To achieve the best rate of penetration, the operator must optimize the hydraulic and mechanical power at the bit. Yet, the small CT limits the flow rate that can be achieved through the pipe. The depth of the hole is also limited by the tension that can be put on the CT while the diameter is limited by the annular velocities that can be achieved outside the CT. Therefore, to determine the technical feasibility of any CT drilling project, each of these items must be evaluated. The following table elaborates the above; Information

Influenced parameter

Hole, casing and tubing sizes Hole, casing and tubing depths.

Annular velocity, CT Reach/ WOB CT reach/WOB

Motor Size

Flow rate, annular velocity

Well trajectory and Total depth

CT reach, WOB, Coil Tubing tension

CT Size and wall thickness

Flow rate, CT reach/ WOB, CT tension

Injector capacity

Depth, CT size

Coil Tubing drilling has limitations, depending on the desired application in drilling. Considering the limitations, coil tubing drilling is specially suited for certain applications. Economical Feasibility Generally, the economic feasibility of a coiled tubing drilling job depends on the location and scope of the project. Evaluating Coil Tubing differs a bit from evaluating a conventional drilling job. With a conventional rotary rig; the required equipment typically arrives on location with the drilling rig. These rigs are built to be mobilized and demobilized many times. In contrast, with a Coil Tubing drilling unit, ancillary equipment is not typically part of the basic rig package and must be rented separately. The pipe, injector head, power pack (for CTU only), Coil Tubing blow out prevents (BOPs) and control cabin can be expected with the Coil Tubing unit. 319


The mud equipment, fuel tanks and pump, generator, electrical equipment, and accommodations are some of the additional surface equipment that may be required. If a job requires pulling or running a jointed completion, a jack-up frame and power tongs will be needed, in addition to the normal completion hardware. Conventional drilling equipment will be required for the bottom hole assembly. For vertical holes, this equipment should minimally include bits, drill collars, mud motor and drilling jars. For deviated /sidetrack holes, other equipment, such as steering and orientation tools, monel drill collars, whipstock, casing collar locator, cement bond tools and mills for window milling, may be required. Acquiring all this additional equipment can be costly and time consuming. For this reason alone, some Coil Tubing drilling jobs may not be feasible and multiwell projects may be required to justify the cost associated with the mobilizing this equipment. The future of Coil Tubing drilling as a commercially viable alternative in the coming days will depend on developments such as the price of oil and the rig day rate charges and other developments such as Coil Tubing drilling specific technology. Some areas for improvement, which will directly impact the economic viability of Coil Tubing drilling, are: z z z z z z

Shorter more flexible BHA, which will allow higher build rates. More reliable and sensitive orienting tool which will allow wells to be steered with more precision and faster. More sensors including for WOB, resistivity etc. Better understanding of Under Balanced drilling (UBD) which will allow us to better optimize potential benefits of UBD for different reservoirs. Improved casing exiting techniques will allow wells to be drilled more economically and in a more wide variety of conditions (casing size, inclination). Hybrid Coil Tubing drilling equipment will bring more versatility and efficiency by allowing operations such as running jointed tubulars in addition to drilling in a single unit.

Conclusions Unless there are specific advantages to be gained from using coiled tubing it is difficult to be commercially competitive. The are however, specific types of drilling operations in which Coil Tubing has a technical advantage and in these situations the economic case is much more easy to justify. The areas in which there are distinct advantages to using coil tubing are: z Through-tubing drilling where the cost of pulling the completion string can be avoided and re-entry is done through the existing completion tubing. z Coil Tubing is a safer and more reliable way of drilling wells in an underbalance state with numerous production benefits. z For pilot or relief wells; Coil Tubing with its pressure seal at surface is ideally suited to these types of wells which are difficult to control by the drilling fluid alone and thus tend to be quite dangerous. z Offshore platforms or remote locations where the cost of rig is often prohibitive. z Location of candidate wells – whether the well is drilled in a remote location or an urban area, offshore or on land, the amount of site preparation needed etc, will have an impact on the commercial viability of Coil Tubing drilling. In areas with environmental requirements, Coil Tubing drilling is often advantageous because fewer rig loads are required and resulting location is smaller than that of a conventional drilling rig. In jungles, mountainous regions, national parks, and urban areas, a small wellsite footprint is desirable to reduce environment impact. In offshore the smaller location need of Coil Tubing drilling unit becomes especially attractive because many platforms have limited deck space. 320

Emerging Technologies z

One of the major factors in the analysis of the economic viability of Coil Tubing drilling is the number of wells to be done in a campaign. There are significant start up costs associated with this service. Increasing the number of wells to be drilled or going to continuous operations would reduce these costs. Continuity of personnel and hence improved efficiency through experience, reduced mobilization costs etc. can be realized in continuous operations.

IV. Slant Drilling

Slant Drilling is the technique of drilling from a slant angle at the surface (45° max. in 1.5° increments), and zeroing in on shallow-depth targets. Slant drilling is an ideal option for reaching target zones that are relatively shallow and may sometimes be necessary to negotiate difficult terrain conditions, such as drilling under bodies of water, population centers or environmentally protected areas. A conventionally drilled directional well is typically started with a vertical section from surface. Specially designed bottom hole assemblies or mud motors are then used to deviate the well at an appropriate angle to reach the target. In contrast, slant hole drilling attains the shortest drilling distance by allowing the well to be spudded at an angle aimed directly at the target. With the proper drilling rig, the well can be drilled straight to the target. The slant hole path can be deviated additionally with the use of conventions directional tools, including into a horizontal direction. The major applications for this technology have occurred in the shallow depth, heavy oil areas. The multi-well pad approach of slant technology is conducive to the drilling of the numerous wells required in these areas. Other applications include wells that require considerable horizontal displacement, especially at shallow depths. Since the 1960fs, the drilling industry has experimented with the concept of automated drilling rigs. In Canada during the 1970’s, small hydraulic rigs were developed for shallow drilling. These rigs featured hydraulic power swivels and partially automated pipe-handling systems that improved 321


both drilling performance and rig move times. An offshoot of this technology was the development of the first slant-drilling rigs which could spud from vertical to 45°. The 1990s saw the revival of slant technology, which was used most successfully in heavy-oil drilling at shallow depths. This differed from directional drilling in several ways: • It followed a shorter, more direct route. Wells could be spudded at an angle—usually 30[degrees] to 45[degrees]—and then aimed straight at the target. • It was less expensive, faster and more productive than directional horizontal drilling. • Slant drilling allowed shallow heavy-oil deposits to be developed from one or several pad locations, which vary in number of wells. Pad drilling also emerged as a way to minimize environmental impact because it allows multiple-well access to larger areas and targets beneath sensitive areas, such as lakes and towns. Precision Drilling Precision Drilling, Canada is the worldwide leader in slant rig technology. Precision Drilling, a division of Precision Drilling Ltd., is Canada’s leading drilling contractor with a well maintained fleet of more than 229 rigs including singles, doubles, light triples, heavy triples, coiled tubing rigs, a surface hole rig along with the skilled personnel to drill at any depth. Their fleet consists of 15 singles, 95 doubles, 45 light triples, 41 heavy triples, 11 coiled tubing rigs, 16 singles and 21 Super Singles. The Super Single rig is ideal for drilling multiple wells from a single location (pad drilling) including drilling in environmentally sensitive areas. For well drilling up to 3000 metres in depth, Precision Drilling manufactures and operates Super Single rigs which feature top drive units, longer range III drill pipe, and automated pipe handling capabilities. These rigs are capable of slant drilling, which is done by tilting the rig mast from vertical. Slant drilling is used to drill several wells from one location, saving the time and avoiding the environmental

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impact associated with setting up a rig in a number of different locations. Slant drilling is also being used by Precision Drilling with increasing frequency in support of the steam-assisted gravity drainage method of recovering bitumen from oil sands. Precision’s Super Single rig, developed in the early 1990s, has evolved over several generations to offer such benefits as fast and simple movement between sites, remote control features that minimize manual labour, control processes that alleviate safety concerns, and the ability to drill a number of different kinds of wells. Once merely identified as a slant drilling rig, the Super Single rig has evolved to become a known versatile drilling rig that is competitive in many drilling operations within a 3000m depth range and is unmatched by any land rig today. This versatility makes the Super Single rig ideally suited to shallow land operations throughout the world. Weatherford International has in September 2005 completed its acquisition of Precision Drilling Corporation’s Energy Services Division and International Contract Drilling Division. Hence now Precision Drilling International is a division of Weatherford and is totally independent from Precision Drilling Corporation.

MULTI-WELL PAD CONFIGURATION `ALL PDI DRILLING UNITS SHOWN IN THE `MULTI-WELL PAD RIG CONFIGURATION’ ALSO CAN BE ARRANGED TO ACCOMMODATEA `SINGLE-WELL PAD’.

A NUMBER OF `SUITCASES’ CARRY POWER AND DRILLING FLUIDS BETWEEN THE TWO COMPLEXES. LEASE DIMENSIONS DICTATE THE NUMBER OF SUITCASES REQUIRED. TYPICAL SUITCASE LENGTH (EA.): 40’ (12m) (PIN-TO-PIN) STATIONARY CENTRAL COMPLEX

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A new generation slant rig’s main rating are as below. 1. Depth Rating: Up to 9,800’ (3,000m) 2. Mast Capacity: Up to 150 tons (133,500 daN) 3. Slant Rig Mast Adjustable Vertical To 45º 4. Travelling Equipment Guides 5. Overall Height: 75’ (23m) 6. Hook Load: 125-150 Tons (111,300 -133,500 daN) 7. Pull Down: 100,000# (44,500 daN) 8. Drill Collars: Up to 8" (203.2 mm) (RII) 9. Hole Size: Up to 26" (660 mm) 10. Casing: Up to 18 5/8" (473 mm) 11. Top Drive Torque: 30,000 ft-lbs 12. Top Drive Speed: 150 RPM 13. Drill Pipe: Range III – 13Mtrs Rig-Design The initial concept for slant drilling was to develop shallow reserves that could not be reached economically with conventional direc-tional drilling. Advances in slant-drilling technology and experi-ence have expanded the slant-drilling role. It now can be considered an economic alternative to vertical development in many cases. Ex-perience with the latest generation slant rig has shown sufficient improvements in performance to reduce drilling costs below those experienced on equivalent vertical wells. The main factors that have contributed to improved rig performance during the past decade include the following. Tubular Handling On most slant rigs, all tubulars are laid down when tripped. This is accomplished with a hydraulic pipe boom that raises pipe from horizontal to the well bore inclina-tion. Pipe Handling The latest generation of top drives used on slant rigs now have hydraulic elevators; thus, only one makeup/breakout is required for each joint. In addition, these top drives have makeup/breakout wrenches allowing connections to be made up/out in the mast as required. The entire pipe-handling as-sembly on the top drive also can rotate 360°. When running casing, this feature acts as an infinite-position stabbing board and provides accurate thread alignment. Drill pipe and casing are made up by the top drive. When ac-curate casing torqueing is required, a power tong can be added with minor rig modifications. Using con-cepts adapted from large power casing tongs, a wrench was built to spin and torque drillpipe, collars, and casing in a single opera-tion. Torques up to 100 000 N-m can be generated with these wrenches. Top Drive. The initial top drives used on slant rigs were modified power swivels, which were adequate for the shallow gas wells drilled. The top drives used on the newer slant rigs are 450 kW units capable of 20 000 N-m drilling torque and 320 rev/min. Fluid Handling On present pads, sumpless drilling is used. The mud is reused up to 16 times. The advantages of sumpless drilling include the following.

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1. Rig placement on the pad is simplified because individual sumps do not have to be worked around. Only a small remote sump is required. 2. By reusing the drill fluids, cleanups are simplified. This reduces the environmental effects of the drilling operation significantly. Fluid Transfer In the latest generation of slant rigs, a small tank is situated at the rig flow line. The following items are designed into the tank. 1. Linear motion shakers at the flow line virtually eliminate solids-generation problems during fluid transfer. 2. All plumbing for the rig’s well control remains fixed. The choke manifold, degasser, and trip tank are incorporated into this tank. This allows for the same well-control hookup regardless of well bore inclination. Remote Tank Design To allow for sumpless drilling, the remote mud tank was designed with the following features. 1. Adjustable skimmers between tank compartments to allow for either top or bottom equalization. 2. A separate suction manifold between the first two compartments to allow flexibility for the cen-trifuge suction. 3. Agitators on each compartment to improve solids removal and prevent solids loading during extended pad operations. 4. Variable-rate chemical injectors for injecting flocculent directly into centrifuges while clearwater drilling on top hole. Each injector should be equipped with an agitated mixing tank. Transfer Umbilical With the advent of electric slant rigs, the transfer of fluid and power between the main and remote rig sys-tems for pad drilling became more complex. Initially, umbilicals on mechanical rigs used cable stands and flexible hose. This sys-tem was adequate but caused freezeup problems during winter op-erations. Today’s electric rig umbilicals typically consist of 10-m enclosed sections. The drilling-fluid, water, steam, and BOP hy-draulic lines run in a heated enclosure with the electrical lines strung above the transfer cases. Rig Mobility The first slant rigs were designed for single-well ap-plications. They were moved in a manner similar to conventional trailer rigs. As pad drilling progressed, the ability to move the en-tire drilling module in a single load was necessary. Pad rigs now are designed with heavy-duty 16-wheeI suspensions beneath the substructure. Each eight-wheel bogie on the suspension is mounted on a turntable allowing rig movement in any direction. The entire rig can be jacked up on hydraulic rams allowing the suspension to be positioned as required. The catwalk end of the rig is mounted on a small skid plate. Once the rig load has been placed on the sus-pension, these rigs are moved with two bed trucks by use of winch lines on either end of the rig. Because they are light, the shaker tank, water tank, and doghouse are skidded to the next well slot. These rigs are capable of rig release to spud times of <5 hours. Safety The development of slant-drilling rigs has resulted in op-erations that are safer than those of conventional vertical rigs. Sever-al safety benefits can be attributed to slant drilling. 325


Pipe Handling All pipe handling is performed from remote lo-cations. Rig crews are never in direct contact with tubulars on the drill floor. Slant rigs are not equipped with catheads or spinning chains. In addition, a derrickman is never required to be in the mast because all pipe is laid down on every trip. Rig Moves During pad drilling, the main power generation, mud system, and mud pumps are never moved on inter-well moves; thus, rig move accidents that occur during this phase of the-rig move are eliminated. In addition, the main rig module requires very lit-tle rig up or rig out on an inter-well move because the entire unit is moved as one piece. Programmable Logic Control (PLC) Most functions for the latest generation of slant rigs are controlled with a PLC. Because all these functions are programmed, the ability to program safety interlocks is very easy. The rig crew cannot perform a sequence of steps that may lead to an accident or equipment damage. The PLCs program can be updated continually as new safety and equipment concerns are identified. Running Casing The entire opera-tion is hands off, including the power tong operation. As a result, accidents while running casing are virtually eliminated. Picker Crane Slant rigs do not have V-door ramps. To allow equipment to be transported to the drill floor, a hydraulic picker is used. Again, the rig crew is removed from directly handling heavy equipment. Blow Out Preventer (BOP) The BOP is nippled up in a slant mode which aligns with the tubular running path, thus minimizing the wear and tear. The topmost pipe is in tension and will be rubbing on the wear bushing in the wellhead. The string is further supported by an hydraulic arm below the drill floor which moves the tubular path to minimize contact with BOP. Remote Control Features Fully mechanized, using state-of-the-art technologies to minimize manual labor, the rig’s remotecontrol features reduce the crew’s exposure to harsh weather. These features include: z Hydraulic tubular handling arm z Hydraulic power wrenches for make-up and break-out of tubulars z Hydraulic power wrench carrier z Hydraulic top drive z Hydraulic BOP handler and hydraulic pulldown z Pneumatic tubular slips z Hydraulic pipe tables for gravity indexing of tubulars and casings to and from the catwalk z Hydraulic tubular kickers and indexer systems that index tubulars from the catwalk individually into the tubular handling boom, or kick tubulars out of the handling boom and onto storage racks or tables. In addition to efficiency gains, this high level of equipment control has the specific benefit of drastically reducing connection times. The hydraulic pipe tables lift joints of drill pipe to the catwalk, where the hydraulic pipe arm is located. The indexers then roll the joints onto the catwalk and into 326


the pipe arm, which lifts the joints individually to the derrick. A top drive screws directly into each joint, eliminating the need for an awkward and heavy kelly. The entire connection process takes less than a minute, a fraction of the usual three to five minutes required by conventional single and double rigs.

The BOP Handler accommodates a 540mm annular BOP

Personnel are required to operate the controls, run the equipment, perform basic maintenance, disassemble the rig and rig up at the next drill site. The chief difference is that the equipment does most of the work, eliminating the labor-intensive and dangerous component of tubular handling. This not only makes the entire process more efficient, but also improves safety considerably. Safety Benefits Special consideration to areas of exposure of personnel to hazardous operations is given during the application and control of the equipment throughout the drilling rig. Being a single style of rig and using equipment to lay down and pickup pipe in all tripping operations, the Super Single rig does not require personnel to be in the mast for anything besides servicing or visual inspections. The mast is hydraulically pinned into position by a remotely operated pinning system. No pins other than safety pins have to be installed or removed manually while the mast is at height. Mast-raising rams are required to be laid down during drilling operations. The rams are fully retracted through all stages and are pinned hydraulically in place. The slip table is designed to accommodate most tubular slip sizes into the power link mechanism, reducing the employees’ exposure to lifting related injuries. The application of a power wrench mounted in a hydraulically positioned cradle reduces the need for manual tongs. 327


Opportunities are constantly being evaluated to reduce further exposure. The simple design of the top-drive and the inherent features of top-drive drilling also provide a safer work environment. The tubular handling arm eliminates several tubular operations from the drill floor, v-door and catwalk - a all high exposure operations on conventional drilling rigs. The tubular indexing system eliminates the need for personnel to be working on the catwalk during drilling, tripping or while running casing. The hydraulic pipe tables and casing racks greatly reduce personnel exposure to the hazards of rolling tubulars. The application of true proportional control on hydraulic functions improves operational control. Maximization of hydraulic and pneumatic control for as many functions as possible can reduce manual- and fatigue-related labor issues. The two operator controls are located beside one another in a way that maximizes operator view for all operations in the well line. Range III tubulars reduce the number of times and operations required to run tubulars, which are the highest incident percentage in drilling operations. Above average usage rates and consistent operator use provide a stable working environment for employees, reducing staff turnover, which can affect the safety of rig operations. The IADC (International Association of Drilling Contractors), CAODC (Canadian Association of Oilwell Drilling Contractors) and Precision Drilling note that the highest percentages of safety-related incidents occur on the drill floor, catwalk and racking areas. The application of improved control of equipment ensures that these percentages are on the decline. Precision Drilling has experienced a 58% reduction in drill floor recordable incidents on Super Single rigs relative to the remainder of the fleet. Slant Drilling Applications 1. Slant drilling was mainly done for exploiting primarily shallow gas reservoirs under bodies of water. The true vertical depths (TVD’s) of these wells typically were 500 to 800 m. Be-cause these reservoirs were shallow, conventional directional drilling could not provide sufficient lateral displacement to penetrate the targets. Using slant techniques, a 300-m displace-ment requires only a 31° well bore path from surface. Up to 500 m of lateral displacement could be achieved with the maximum al-lowable spud angle found on slant rigs, 45°. 2. Pad drilling for shallow wells in environmentally sensitive regions. A full section of land (four wells per section) can be drilled from a common surface location. This greatly minimizes the environmental effects of road, lease, and tie-in construction. 3. Slant wells to avoid irrigation systems. Surface sites for shallow wells frequently are set too far back from the downhole targets to be reached economically with convention-al directional-drilling techniques. 4. Slant drilling beneath city and town boundaries where it is unfeasible to obtain surface leases above the target horizon 5. Slant drilling extended-reach wells beneath rivers and lakes. 6. Slant drilling for installation of pipeline crossings beneath rivers, highways, and ocean- and beach-front approaches 7. The latest generation of Slant rigs enable drilling of wells requiring large lateral displacements with minimal directional costs. Future applications envisage up to 3000 m of lateral displace-ment in a well of TVD - 3000 m (i.e., a 1:1 TVD/lateral displacement ratio). 8. Extended-reach development of reservoirs below lakes and rivers now is more feasible. Plans are in progress for 2000 to 3000 M lateral displacements under lakes in southern Alberta. These reser-voirs lie at approximately 1000 M TVD. 9. Horizontal drilling in reservoirs that require large lateral dis-placements before turning horizontal now can be achieved. 10. Environmentally sensitive regions are excellent candidates for slant drilling. 328


World Scenario & Advantages Over the past many years, many companies like EOG Resources Canada, Inc., Petro-Canada etc., have used the rig for well depths of 1,500 ft to 7,500 ft (500 m to 2,300 in), because of greater flexibility and savings in rig time and operating costs due to the rig design’s efficiencies and ruggedness. Penetration rates of 500 ft/hr (150 m/hr) have been experienced almost doubling the drilling efficiencies. Also observed are quicker connection times, as the drill pipe is 45 ft (13 m) long—that’s 50% more than conventional single rigs, which use the standard 30-ft (9-in) drill pipe. Perhaps one of the biggest time savers, is the Super Single’s design of the remote-controlled tubular handling equipment and the top drive. Rather than manually racking the drill pipe on the rig floor before logging, a hydraulic arm operated remotely by the rig crew lays the drill pipe on the pipe racks. Once logging is completed, the casing can be run immediately because the pipe has already been laid down. In addition to the same 50% reduction in connection time, it is easier to orient downhole motors and back-ream with the rig. Petro-Canada has been able to move the rig and spud the next well in less than two hours from the time it’s released from the previous well. With four pads and 50 wells, the rig’s mobility was a significant factor in improving the efficiency of PetroCanada’s drilling program. Part of the rig’s efficiency also has to do with the top-drive design. The rig is much faster because you’re operating at a higher range of rpms and you can have much quicker connection times. The top-drive capabilities also reduce the risk of experiencing stuck pipe. In a eight month period. PetroZuata also experienced faster rig moves compared to conventional drilling rigs. Normally, conventional rigs take at least 30 hours to move from pad to pad. The rig (PD 735) used by PetroZuata took only 15 hours to move to another pad. Due to its size and compact design, the rig can be prepared to move in two hours and rigged up in the same amount of time. Continuous back-reaming was also listed as an advantage of the rig because each joint is handled by making up the top drive into the pipe. The rig can pick up casing joints as regular joints and run casing without needing a power tong. The necessary torque for the casing can be applied by the rig’s top drive system. In PetroZuata’s case, PD 735 Super Single rig broke a world record in drilling time, achieving 5,193 ft in one day. The rig routinely drills 8,000-ft measured-depth horizontal wells at a true vertical depth of 2,100 ft without any issues. Overall, the rig had no significant limitations with the exception of its drawworks and pulling capacity. The small size may pose problems for some of the larger projects. Indian Scenario Precision Drilling had been awarded a drilling contract by Niko Resources Ltd. to conduct work on its onshore Surat Block in the Gujurat state of India. Niko utilized a semi-automated, super single slant rig “PD 709SLE”. The approximate contracted operating cost per day in 2002 was US$ 13,000 in vertical mode and US$ 18,000 in slant mode. The rig was to have drilled an estimated 15 wells on the Surat appraisal program in both vertical and slant modes. The rig was chosen as it was particularly suited for drilling applications in environmentally sensitive and limited size locations, attributes that are essential for the Surat Block. Drilling was to have been carried out for reservoirs below the city. However after drilling the first appraisal well in slant mode, and after re-evaluating the seismic data, it prospects in the inaccessible areas were down-graded. Hence the rest of the locations were drilled in the vertical mode. Later, more wells were drilled by Cairn Energy in Rajasthan using this rig in vertical mode. Multi well pad drilling was carried out for the development wells. 329


Summary Although slant drilling is a technology that has been in use for many years, the latest generation of slant rig designs, known as “Super Single” enables newer rigs to do more than drill at an angle. The phrase ‘super singles’ when the rigs were extended from Range II drillpipe that’s 9 m long to Range III drill pipe that’s 13 m long. These designs incorporate the latest drilling technology to accomplish a variety of drilling tasks. These rigs are designed for slant, vertical, directional, and horizontal drilling, and incorporate safety and control features, along with swift rig up, rig down, and moving capabilities as priorities. The rig handles casing and drillstring tubulars without exposing employees to the heavy labor normally required on conventional drilling rigs. The new rig also could drill multiple shallow wells from a single pad, generating minimum disturbance to the wellsite environment. The rigs have remotely controlled tubular-handling systems, masts that can tilt from vertical to 45 degrees in 1.5 degrees increments, and reversible single or dual-speed top drives. One key advantage to starting a well at a sharp incline is the reduction of wellbore build rate from vertical to horizontal - a reduction in dogleg severity-during the drilling of very shallow horizontal wells and reduced measured depth of a directional well. On these rigs, two operators, the driller and the derrickman, use remote controls to accomplish the handling of all tubulars. The system requires no roustabouts or roughnecks to physically move tubulars from racks to the catwalk or to manipulate them on the rig floor. Removing personnel from hazardous environments and heavy, repetitive work typically involved in tubular handling has resulted in a significant improvement in rig floor and catwalk safety statistics associated with these rigs. The derrickman operates a hydraulic power wrench for tubulars makeup and breakout, and the carrier for positioning it. He also controls a tubular kicker and indexer system that can index tubulars from the catwalk, individually, into the tubular-handling boom, or kick tubulars out of it onto the racks or tables for storage. Using the automatic controls, he places all tubulars in the hydraulically activated tables and racks. When he moves the desired tubular to the catwalk, the hydraulic tubular-handling boom lifts it to the rig floor. Once the tubular is on the rig floor, the derrickman remotely operates the power wrench for makeup. Similarly, when coming out of the hole, the tubulars are laid down and returned to the racks or tables via remote control, without any manual intervention. The driller remotely operates air-powered tubular slips for drill tubulars and hydraulic catheads for use with manual tongs when a power wrench is not applicable. He also operates the hydraulically powered, pull-down system for inducing artificial gravity on long-reach, horizontal well sections and a single or dual-speed, reversible top drive with integral traveling block and orientation lock. The rig has reduced connection times, to 30-45 sec for this slant rig compared with 3-5 min for conventional, telescoping double, or other single slant rigs. The drilling system is designed around the use of: 1. 45-ft lengths of drill pipe (API Range III) with diameters up to 51/2 in. 2. Heavy-weight drill pipe in conventional lengths (API Range II). 3. Drill collars in conventional lengths with diameters up to 8 in. 4. Casing in conventional lengths (API Range III) with diameters up to 133/8 in. The driller uses a remotely controlled hydraulic system to set the blowout preventer (BOP) at the correct angle for the wellhead, and the fluid containment system keeps to a minimum any fluid loss due to the angle of the BOP while maximizing fluid head for fluid transfer to the shale shakers Safety Benefits. Most injuries to drilling crews occur while they are handling tubulars, with most of those injuries occurring on the rig floor and catwalk. The rig’s control processes help to alleviate this problem. The remote-controlled hydraulic tubular handling boom enables the derrick-men to safely remove and add tubulars and accessories to the drillstring mechanically rather than manually. 330


The boom also provides for the handling of casing. Drilling crews no longer must move tubulars from racks to the catwalk or position them on the rig floor. Beyond that, hydraulic safety lockouts for mast position pinning and crown maintenance reduce the need for personnel to climb the mast. Drilling Efficiency and Versatility The rig can drill vertical, deviated wells, and under-balanced wells to 3,000 m (MD), though the average measured depth of wells drilled worldwide by slant rigs is around 950 M. The sixth-generation rig design uses “programmable logic controls” to monitor the position of traveling blocks and employ a fail-safe disc brake to control the block speed as it approaches the crown. The system also slows the block as it nears the rig floor. This level of PLC control enhances process efficiency and helps prevent potential damage to the rig floor and the crown. A tri-parameter auto-drilling system enables the controls to make adjustments on its own if drilling should deviate from safe operating parameters, thus reducing the potential for human error. By presetting safety limits on other operating parameters, the control system is programmed to sound alerts and keep the drilling system operating within safe limits while the driller analyzes any deviations and takes corrective action. PLCs, reduce the many control lines to one, on which the signals for the various rig systems are multiplexed. The result is a simpler system that can be rigged up and down more quickly The rig can be moved quickly. The slant rig’s tubular handling system lays down each joint during every trip out. The tubulars can be moved at any time without breaking down stands. The rig design is also simple and compact, requiring only eight loads for well-to-well movements on a pad (including boilers and tubulars). In some cases, movements on a pad can be completed within two hours. The rig can also be moved one to two miles in four hours and is easily disassembled for highway transportation. These rigs are presently used in Canada, China, Mexico, Brazil, Venezuela and Kazakhstan. Conclusions The use of slant drilling is a proven economic method of drilling in many countries worldwide especially in Canada, China, Venezuela etc. for shallow development wells mainly in the range of 400-800 M TVD. Recent advances in slant tech-nology have made it possible to exploit many fields up to 3000 m deep at costs below those for conventional vertical development. The latest generation of slant rigs have proved the following. 1. Pad drilling for conventional shallow depth reserves can be done economi-cally and with minimal environmental effect. 2. Well cost for shallow directional wells reduces since only holding assembly is used and well’s measured depth is reduced in slant drilling. 3. Slant drilling, as compared with conventional directional drill-ing, can lower production operating costs for wells that will re-quire artificial lift. This is achieved through smoother well bore profiles that minimize rod and tubing wear. 4. Advances in drilling-crew safety can be achieved through de-sign improvements to drilling equipment and techniques. 5. PLC of medium-sized electric land rigs is very effective. 6. Sump less drilling can be achieved economically on medium-depth land rigs and will reduce the environmental effect of drilling-fluid wastes significantly. 7. Top-drive technology can achieve both economic and perform-ance advantages over rotarytable drives on medium-depth land rigs. The main disadvantage of this technology apart from the high cost is that since the wellhead is tilted work-over can be done only by Slant Rig and not by conventional rig. 331


V. Hole Enlarging & Under Reaming Introduction When using standard reaming techniques to enlarge open hole sections, operators have normally drilled a pilot hole to the next casing depth and afterwards run an expandable-arm under reamer. In some cases, reaming the hole to its targeted diameter was more time-consuming than drilling the pilot hole.

Besides the direct costs associated with reaming, frequent downhole tool failures, in particular the loss of under reamer arms and pins, severely affected total well economics. Furthermore, the historically low penetration rates (ROPs) prevented operators from optimizing drilling efficiency. With the development of rotary drilling and increase of borehole depths, ideas were developed by engineers for decreasing drill string tripping time to change the worn bit. The development of a bit, which could be run down and pulled out of the bottom hole inside the casing or drill pipes by the wire line was the principal answer. Hence the term Retractable Bit (RB).This kind of tool provides the possibility to realize the method of drilling without pulling out the pipes (DWPP), which has substantial cost benefits in the process of construction of a borehole or one of its intervals. One embodiment of the technique of drilling with casing requires a bit that can be retrieved through the existing casing string. To achieve this and to maximize drilling performance requires a device with a formation cutting structure indistinguishable from a standard PDC drill bit but capable of being withdrawn through a restriction significantly smaller than the borehole size just drilled. This concept leads to the possibility that a viable solution to the task of drilling increased diameter holes could be a bit that offers substantial expansion capabilities while still presenting full cutting structure to the formation. Hence the concept of expandable bit was born. Initial efforts to circumvent the economic and technical drawbacks of standard under reaming techniques focused on bi-center PDC bits. Because of its unique geometry, a bi-center bit can freely move to one side of the hole during the trip through the casing and effectively drill a hole size larger 332


than the inner diameter of the casing through which it passes. Although a step-change improvement over standard under reaming, bi-center bits are not without operational problems that can negatively affect drilling costs. Warren, et al., perhaps best amplified the difficulties associated with the use of bi-center bits for opening holes. Foremost among the problems are deviation tendencies that make these bits extremely weight sensitive when run on rotary drilling assemblies. Because only stabilizers matching the pass-through diameter can be used, deviation control is difficult. The cocking (walking) tendencies of bi-center bits generate unusual wear patterns, making it challenging to affect proper stabilization. This propensity places severe limitations on rotary speed, thus lowering penetration rates. Aside from low penetration rates, bi-center bits have not eliminated drill string failures, abnormal tool wear, and instances where the reamed interval was not as large as that stipulated in the well plan. In the majority of wells drilled onshore Venezuela, the shortcomings of bi-center bits in reaming operations were even more pronounced, particularly in the upper sections, which are highly prone to bit balling. As such, the shallower fluid courses of one-piece bi-center bits significantly restrict hole cleaning in those intervals. Furthermore, the abnormal pressure characteristic of Venezuelan wells requires the setting of maximum-diameter liners throughout the well bore to minimize hole loss. This requirement and the wide variance of formation composition require flexibility in the size and type of pilot bits and bottom hole assemblies. Standard bi-center bits do not afford this flexibility. The ability to drill and ream in a single pass has become even more advantageous as the global trend toward deeper, high pressure, high temperature wells increases. Because of the extra casing strings and longer intervals often drilled through unstable or encroaching formations, operators have recognized the enormous economic advantages of simultaneous drilling and reaming. Contemporary exploration trends and the documented limitations of both bi-center and traditional hole opening technology spurred the development of the ream-while-drilling tool. The ream-while-drilling (RWD) tool is a two-piece system that, unlike traditional under reamers, incorporates no moving parts. This design eliminates the risk of leaving metal parts, such as under reamer arms and pins, in the hole. The first section of the tool consists of the pilot bit; the second is essentially a tube incorporating either four or five fixed blades with PDC cutters. The position of fluid jets on only one side of the tool enables eccentric rotary movement to widen the pilot hole. By virtue of the two-piece configuration, the type and size of both the pilot assembly and bit depends only on the design of the specific tool. Thus, either a PDC or roller cone bit can be used, depending on the formation composition. Under Reaming Technologies Under reaming is a complex market consisting of at least 22 drilling applications. Under reaming offers several product options, including bi-center bits, reaming wing tools, expandable bits and under reamers. In terms of product selection and application, the variety of available options presents a dilemma to the drilling professional. The accompanying box provides a list of strengths and limitations for retractable drill bits, bi-center bits, reaming wing tools, and under reamers. Two hole-size categories171/2 to 36 in. and 43/4 to 171/2 in.-were created to aid in the analysis.This was also intended to identify any trends that may emerge as to product preference and hole size. Because of the technical differences between hole openers and under reamers, hole openers have been excluded from the market analysis. Hole openers start to enlarge an existing pilot hole from the surface of the well bore and contain fixed cutters of a predetermined diameter. 333


Conversely, under reamers enlarge the hole below a restricted tubular bore. The cutters are kept closed during the pass-through and are activated once the tool reaches the point that requires under reaming. Turning the pumps off deactivates the cutters with this technology.

334


1. Under reamers Originally, under reamers were only used to under ream previously drilled holes, involving an additional trip. Typical design features included flow or weight-activated arms that expanded on a pivot-bearing mechanism.

For the purpose of drilling oversized hole sections, the Anderreamer uses a unique combination of mechanical and hydraulic mechanisms to extend the cutter blocks.

An example of the limitations associated with this type of technology can be seen in runs where traditional arm-type under reamers have led to failures, often resulting in a sidetrack. Reportedly, under reamers have difficulty coping with deviated wells and hard chalk. This has raised concerns regarding the effect of bending stresses on the body and connections. Another problematic area includes mud packing. When this occurs below the arms, it can prevent them from closing in, making it extremely difficult to pull out of hole. Historically, these factors have swayed decision making in regards to its use. Even today, under reamers still have a way to go in terms of improving mechanical integrity and shedding a poor image. To improve the mechanical integrity of traditional arm type under reamers, several things happened. First, the development of polycrystalline diamond compact cutters eliminated problems associate with mud packing and arm breakage. Thus, typical tool life was extended to 10 runs or more. A further procedural innovation involved the removal of all cutters from worn roller cones, replacing these with new cutters. These cutters were stub-welded in place once fatigue became an issue. Three-cone under reamers have been capable of enlarging holes by as much as 50%, typically selected according to formation type so as to optimize performance. The tools also allowed full volume circulation at all times. It is convenient to classify the various reamers as either drilling or reaming types. The reaming type serves only to enlargen an existing hole, involving complete section redrill. Conversely, the drilling type allows for the simultaneous reaming of a pilot hole as it is drilled. It can also be used to under ream existing holes. Its design allows mudflow to be diverted to the bit or can even be used with guidance system such as a bullnose for pilot-hole reentry. 335


The latter has been reported to give good hold or slight build tendencies, depending on formation and other factors. Thus, its performance resembles a packed-hole assembly. 2. Retractable Bits (RB) First projects of DWPP occurred at the beginning of 20th century. Drilling method with RB and DHM was proposed in 1902. The attempts were made after the First World War of this method realization in Poland, and a little bit later in France (1928). Over the same period (20s-30s) great interest to RB was displayed in the USA. The bit designs with retractable blades operated worse than standard two-blade drag drilling bits (“fish-tail” bits). In 30s, three-cone rock bits were introduced as the main type of rock destruction tool. First designs of cone rock RB were patented in the USA before the Second World War. This kind of tool provides the possibility to realize the method of drilling without pulling out the pipes (DWPP), which affects substantially the process of construction of a borehole or one of its intervals. Subsequent to the development of rotary drilling and the increase of borehole depths, the concept of decreasing drillstring round-trip time to change the worn bit was devised. The development of a bit that could be run in and pulled out of the bottomhole inside the casing or drillpipe, using a wireline or drilling mud circulation was a logical solution. These bits were used in two modes: (1) working - for bottomhole destruction (2) transport - for moving inside the pipe The bit name, Retractable Bit (RB) derived of this application. The use of RB allows drilling without pulling out the pipe (DWPP) and substantially affects the process of construction of a borehole or one of its intervals. DWPP features are as follows: • continuous flushing of the borehole during the RB operational cycle: running in, drilling, pulling out • replacement of the different purpose tools (drilling, coring, and milling) without pulling out drillpipes • carrying out logging operations without pulling out drillpipes • relief of the workload on drilling rig crews This required among others: • more complicated bit design • special or larger ID flush joint drillpipe • special design BHA, including retrievable BHA (RBHA) and connection to drillstring • latch and seal unit for RBHA The real advantage of the RB technology - simultaneous borehole drilling and casing. Unfortunately, the quality of standard casing pipes and particularly types of thread connections did not allow using them for DWPP especially in hard formations. Nevertheless, this trend of RB use could be one of the major tasks for future research, because it brought revolutionary changes in the entire drilling process. RB Technology Prospects 1) Drilling with casing – this is most promising trend in cost-effective technologies for 21st century. 2) Super-long boreholes drilling – RB could provide drill string tripping timesaving, better well control and borehole walls stability in 10-15 km long wells. 336


3) Scientific drilling – RB provides unique opportunities for continuous coring and logging operations in all kind of geological conditions both onshore and offshore. 4) Geothermal drilling – drilling with retractable bits makes available cost effective deep geothermal drilling in hard crystalline hot formations. 3. Expandable Bits Two techniques directly applicable to, and positively impacted by utilization of an “Expandable Drill Bit” are the use of expandable casing and drilling with casing. One method of drilling a monobore well is to use a drilling device capable of passing through a restricted diameter, with the ability to drill a larger diameter hole. Similarly, when drilling with casing, one method is to drill the borehole and then recover the drilling device through the bore of the casing just installed. The present design of the expandable bit was prepared after considering a number of options and alternatives and was seen to embody the features associated with best drilling practice. Design Basis The original design premise was to build a drill bit with a variable diameter PDC cutting structure using a simple, robust and reliable operating mechanism. Following assessment of a number of alternatives, a concept design with four moveable blades was selected. This initially achieved an expansion from 8 ½-in. to 9 5/8-in., although very early on this was increased to 10 3/4-in. This resulted in an expansion ratio of 20%. It was realized that this would not only make selection of the right drilling application much easier, but also achieve a significant performance improvement over existing oversize hole drilling methods, such as under-reamers and bi-center bits. It also quickly became apparent that the design allowed much larger expansion ratios to be achieved with minimal 337


The expandable drill bit’s closed configuration is shown on the left with the expanded mode on the right. During field tests with Unocal in Indonesia, weight on bit required to achieve a specificed controlled penetration rate was 30% lower than for offset tricone runs.

alterations in the blade design. The expansion mechanism is entirely hydraulically actuated by the pressure differential from fluid flowing through the bit. An internal coil spring is incorporated to return the blades to the closed position. This would occur every time flow through the bit stopped. Operational Feedback and Product Development It was evident that debris contamination along the underside of the blades could prevent the bit from closing satisfactorily. Also, drilling debris was entrained within parts of the blade guide slots. It was recognised that preventing ingress and entrapment of debris to the working parts of the bit would be impossible, so the alternative was to insure, as much as possible, that no entrapment could occur. Accordingly, the slots in the head were considerably relieved, retaining only sufficient material to ensure necessary structural integrity. The lower faces of the blades were also re-profiled, with a blunted knife-edge, to displace any solids accumulating underneath them. (The slots in the blades, engaging with the return pins were replaced with grooves on the front and back faces and the pins were re-designed accordingly.) In an attempt to provide a pressure sensitive open/closed indicator, small by-pass ports were drilled into the head of the bit immediately below the lower face of each blade. The lower face of each blade was provided with a rubber plug, to prevent flow when the bit was closed. The ports would have the additional feature of washing out the lower face of each blade during drilling operations. Some damage was evident to the bore of the hydraulic cylinder, caused by contact with the outer diameter of the piston. Although the original design concept had attempted to keep the number of parts to an absolute minimum, to increase reliability, it was decided to fit bronze wear rings between the piston/cylinder and cylinder/mandrel interfaces. These were retrofitted to the prototype and could easily be replaced in the field. Flushing ports were also introduced into the hydraulic cylinder to enable cleaning of the actuating chamber and spring chamber without necessitating stripdown during field operations. 338


Summary and Future Developments Developments of the expandable bit have proved the concept to be feasible and practical. Supported by continuous development in association with Unocal, this project has provided performance improvement and addressed all necessary operational issues. 4. Bi-center bits

Fig. 4.

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In 1994, bi-center bits were introduced, which contained new technology. For the first time, a single tool could reliably be used to simultaneously drill and under ream, even in highly directional applications, all with no moving parts. The results were fewer trips, fewer rotating hours, and less “problem” time. The only major draw back to using bi-center bits has been that they could not be used to drill out cement, float equipment, and casing guide shoes. It was required that a conventional drill bit be used first to drill out into new formation, then a trip was needed to pick up the bi-center bit. In 1999, advancements in bi-center technology have resulted in a bi-center bit that can be used to drill out and then continue to drill ahead. Gradually, increased demand for these bits highlighted certain technological limitations, including poor directional drilling performance. Essentially, this was linked to the lack of a full-gauge stabilizer above the bi-center bit, resulting in bottomhole assembly (BHA) stabilization issues. Without stabilization, there was a need to depend almost entirely on the bent motor housing to steer. BHAs using bi-center bits tended to have a problem with inclination control. Consequently, to make changes in inclination, drillers spent a lot of time slide drilling, which can be difficult at the best of times, let alone with the added complication of running a bit that is geometrically unstable. From this perspective, there was an understandable apprehension towards running bi-center bits. As steerability issues continued to hinder directional performance, bi-center bit manufacturers have found ways to improve BHA behavior. These companies realized that bi-center bits could to an extent be steered by weight alone. They also found that longer bit profiles helped to stabilize BHA performance. Today, bi-center bits are used in hard formations as they are perceived to be more robust than traditional arm under reamers. On the other hand, under reamers tend to be preferred in softer formations as their application can lead to impressive gains in penetration rates while providing an increased time window to conduct operations in swelling formations. The success of bi-center bits removed the need for hole openers in many applications, eliminating the need to drill the interval twice. From the drilling engineers’ point of view, a single integral component reduced risk and cost as compared to two or three. All these factors came together to confirm the place of the bi-center bit in the industry. Bi-center bits often produce excitation force required to induce vibrations that are then detrimental to drillstring and BHA components, It is also felt that they do not drill out shoes as efficiently as predicted. Finally recent calliper logs run in the GOM illustrated that large sections of the wellbore had not been enlarge “opened up” at all. 5. Reaming Wing Tool Another technology is the reaming wing tool. This technology features a polycrystalline diamond compact bit with a ream while drilling capability. This tool differs from bi-center bits in that it features a two-piece design, allowing for greater flexibility in pilot bit selection. Directional control is conducted through a steerable motor. With all factors duly considered reaming wing tools may have some potential for use in deep open water applications, notably in shallow high angle wellbore field developments. Design The ream-while-drilling (RWD) tool is a two-piece system that, unlike traditional under reamers, incorporates no moving parts (fig. 1). This design eliminates the risk of leaving metal parts, such as under reamer arms and pins, in the hole. The first section of the tool consists of the pilot bit; the second is essentially a tube 340


incorporating either four or five fixed blades with PDC cutters. The position of fluid jets on only one side of the tool enables eccentric rotary movement to widen the pilot hole. The pass-through is the drift diameter of the casing or the liner through which the system must pass. Drill size is the final drilled hole diameter. The drill size of the targeted section, in conjunction with the pass-through diameter stipulated in the well objectives, determines the pilot bit diameter.

Fig. 1. By virtue of the two-piece configuration, the type and size of both the pilot assembly and bit depends only on the design of the specific tool. Thus, either a PDC or roller cone bit can be used, depending on the formation composition.

Fig. 2. The geometry of the RWD tool revolves around three interrelated diameters: pass through, drill size, and pilot bit

The geometry allows the tool to adapt easily to the maximum diameter of the liner or casing in which it must pass. Upon rotation, the tool is then able to widen the hole to its programmed final diameter. The leading, or hole opening, blade creates a smooth transition from the pass-through size to the drill size, providing faster stabilization of the system. The pilot bit stabilization pad offsets the net imbalance force of the reamer blades, thus providing the additional stabilization not possible with bi-center bits. Basically, the stabilization pads force rotation around the center of the pilot hole, ensuring the drilling of a full-size well bore. Both the pilot hole size and the extent of the imbalance force generated determine the size of the gauge pad. The reamer wing has carbide-supported edge PDC cutters. The shape of these new-generation cutters strengthens the diamond edge and delays the onset of fracture and cutter wear. By spreading the cutter arrangement across the profile of the tool, the RWD tool designers successfully facilitated even load distribution. 341


The cutter surfaces are highly polished, which is especially advantageous when sections prone to bit balling are drilled, such as those encountered in the upper hole of Venezuelan wells. Polished PDC cutters have a friction coefficient of 0.1, or that of ice sliding on ice. Polished cutters reduce the penetration rate limitations posed by the built-up edge that forms when an amount of drilled formation is not removed and subsequently attaches itself to the leading edge of the cutter. Polished cutters reduce the shear forces that restrict cuttings removal and limit penetration rates. The polishing process also removes any microscopic imperfections in the cutter, further enhancing cutter durability. The future of under-reaming technology The three main characteristics of the under reaming market, increased production, cost cutting, and technical innovation in well design show promise for the future. Moreover, strong market drivers in the short, medium, and long term will tend to encourage conditions apt for growth. Increased production Increased production is important for two major reasons. First, depleted reservoirs result in lower reservoir pressures and poorer rock mechanics, further heightening the likelihood of sand productivity. In these instances, to preserve or improve production rates, provision must be made for sand exclusion through pre-wrapped screens or gravel packs. Consequently, the need for enlarging holes to place new sand screens and gravel packs also arises. Eventually, the demand for remedial work such as drilling through failed screens will place additional demand on under reaming technologies. Depleted reservoirs are also likely to result in transition from oil to gas production. As such, the use of under reaming technologies to configure larger bore casing strings can be viewed as a preferred method of improving productivity by maximizing the size of the borehole in the reservoir section of the well. The bracket of increased production also covers older platforms. Decommissioning has proved to be complicated, time consuming, and expensive. These costs tend to dissuade operators from such activities, enhancing the appeal for extending platform life. This can also heighten demand, as certain technical restrictions can be associated with older platforms. These restrictions include the availability of conductor slots and the size of blowout preventers, which restricts bit diameters and conductor placement. Both of these examples make under reaming an attractive option, as it overcomes such limitations while maximizing the configuration of casing strings. Finally, under reaming technologies can be applied towards sidetracking and multilateral drilling applications where hole enlargement through existing casing strings provide an attractive option.

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VI. Laser Drilling Introduction Laser Drilling is a revolutionary method of using laser beams to drill oil and gas wells. The term LASER is an acronym for Light Amplification by Stimulated Emission of Radiation. Albert Einstein, in 1917, predicted the possibility of stimulated emission (generation of photons or discrete bundles of energy via transitions between atomic or molecular energy levels). The first working laser was made by Theodore H. Maiman in 1960 at Hughes Research Laboratories in Malibu, California. • “To lase” means “to produce coherent ABSORPTION (consisting of waves of a single wavelength, in which all the waves reinforce one another) light” and also “to cut or treat with coherent light” • A laser is basically a device that converts EXCTTATION energy of some form (electrical, chemical, heat, etc.) into photons (electromagnetic radiation) • The photons created through stimulated emission form a narrow beam of SPONTANEOUS EMISSION monochromatic, coherent light that when focused into an intense beam can be used to POPULATION OF ablate {spall (chip/ fragment), fuse (melt) and/ METASTABLE STATE AND BUILD UP OF STIMULATED or vaporize} a target depending on the power EMISSION ALONG AXIS delivered. • Lasers can operate in continuous-wave (CW), STIMULATED pulsed, and repetitively pulsed (RP) modes. EMISSION Laser Construction 2 3

RETURN TO GROUND STATE

4

1 5

Principal components 1. Active laser medium 2. External energy pump 3. Mirror 4. Partial mirror 5. Laser beam Application of Lasers • Medical: In surgery – as a scalpel, to reattach retinas and to stitch up incisions after surgery by fusing together skin • Entertainment & Advertising: These use lasers that are in the visible spectrum to paint images in the air. 343


• • • •

Computers and Music: One popular use of lasers is optical drives. Metal working: Lasers allow better cuts on metals and the welding of dissimilar metals without the use of a flux. General Purposes: Lasers are also used to align pipes and wheels, measure speed and distances, read bar codes etc. Defence: Lasers track & destroy missiles etc.

Oil & Gas Industry: Projects are being carried out to drill & complete oil and gas wells with lasers. Given below are a few of the expected applications in oil & gas industry • vertical & directional (including extended reach) drilling, • seismic shot holes, • Cutting windows for side tracking and laterals • cutting trenches for pipelines, • small diameter exploratory wells, • horizontal and slanted wells, • removal of objects lost downhole that would normally require drill out or fishing operations. • primary perforation to create the path between the wellbore and reservoir • extend perforations to connect additional reservoir rock to the wellbore (fracturing) • Laser technology can also be applied to other arrears that require rock removal, such as, mining, excavation, tunneling, nuclear reactor decommissioning, archeological investigation, drilling volcano artificial chimneys for pressure relief, geothermal wells, etc. Types of lasers The laser medium can be a solid, gas, liquid or semiconductor. Lasers are commonly designated by the type of lasing material employed: • Solid-state lasers • Gas lasers • Excimer lasers • Dye lasers • Semiconductor lasers or diode lasers • Fiber lasers Laser Drilling Concept • Laser applies infrared energy to the working face of the borehole and ablates the rock by spallation, fusion or vaporization. • The down hole assembly includes sensors that measure standard geophysical formation information, as well as imaging of the borehole wall, all in real time. • Excavated material is carried to the surface as solid particles / vapour. • When desired, some or all of the excavated material is melted and forced into and against the wall rock to line well bores for well stabilization and abnormal pressure control. • When the well bore reaches its target depth, the well is completed by using the same laser energy to perforate through the ceramic casing. • All this is done in one pass without removing the drill string from the hole. Laser Drilling Action High power lasers can be used to destroy rock in two ways: • by weakening the rock prior to application of mechanical tools 344


•

by direct rock destruction via ablation. Each of the three methods of ablating rock (spalling, fusing or vaporizing) may have specific applications for natural gas drilling and completion.

There are three processes by which lasers might transfer energy into a rock target: • Absorption • Reflection • Scattering It is the absorbed energy that gives rise to rock heating and destruction. Reflection and scattering represent energy losses in the process of rock destruction. The degree to which energy is lost dictates the effectiveness of the laser’s ability to spall, fuse or vaporize rock. Basic benefits of laser drilling • Non-contact process (no tooling wear or breakage) • Highly accurate and precise control of heat input • Ability to produce small diameter holes with high aspect ratios • Ease of programming and ready adaptability to automation • No out-of-balance or out-of-axis turning is expected to occur with a laser drilled hole because photons travel in straight paths. Benefits to Oil & Gas Drilling • Could significantly increase the rate of penetration (ROP) and thus reduces overall drilling costs • Since a sheath will be formed around the hole drilled, casing & piping can be eliminated/ along with all equipment and operations (like tripping etc.) associated with this. Likewise downhole problems like caving, loss etc. are reduced. • Provides perforating and side-tracking capabilities. Also eliminates/reduces • Rig size • Power consumption • Mud/chemical requirement • Bit costs Laser Drilling Research Worldwide In 1994, the U.S. Congress issued a mandate to transfer the laser technology developed for the U.S. Department of Defense’s Star Wars project to civilian applications. In 1997, the Gas Research Institute called for proposals to revolutionize drilling. ‘Colorado School of Mines’ and ‘Solutions Engineering’ submitted proposals for applying star wars laser to drill and complete wells. They demonstrated the feasibility of using high power lasers for oil and gas applications. Consortium partners in this research with DOE were Colorado School of Mines, Gas Technology Institute, U.S. Geological Survey, DOE/NGOTP (Natural Gas and Oil Technology Partnership), U.S. Air Force, Argonne National Laboratories, Halliburton, N.A. Technologies, Parker Geoscience, Occidental Petroleum, Boeing Intellectual Property Business, IPG Photonics (IPG) and the Venezuelan National Oil Company (PDVSA). Research Objectives • To obtain much more precise measurements of the energy requirements needed to transmit light from surface lasers down a borehole with enough power to bore through rocks as much as 6000M or more below the surface. 345


• • •

To determine if sending the laser light in sharp pulses, rather than as a continuous stream, could further increase the rate of rock penetration. Pulsed lasers have been used for better performance in cutting rocks. To determine if lasers can be used in the presence of drilling fluids. The technical challenge will be to determine whether too much laser energy is expended to vaporize and clear away the fluid where the drilling is occurring. A variety of lasers have been used in the research. The following table shows the lasers, location, and laser properties.

LASER

Location

Wave length (µm)

Power Used (kW)

Mid-Infrared Advanced Chemical Laser (MIRACL)

US Army, White Sands, NM

2.6 to 4.2

900

Chemical Oxygen Iodine Laser (COIL)

Kirtland Air Force Base, Albuquerque, NM

1.315

8

Pulsed CO Laser

Lebedev Institute, Moscow, Russia

5 to 6

6

Pulsed CO2 Laser

Lebedev Institute, Moscow, Russia

10.6

6

CO2 Laser

Wright Patterson Air Force Base, Dayton, OH

10.6

8

CO2 Laser

Argonne National Labs, Chicago, IL

10.6

10

Nd:YAG

Argonne National Labs, Chicago, IL

1.06

6

Direct Diode

Native American Technologies, Golden, CO

0.8

4

Figure above shows experimental set-up for Nd:YAG Laser interacting with rock

346


A comparison of laser parameters for industrial lasers at 4KW power output is given in table below.

Spectroscopy is used in determining the amount of energy reflected, emitted, and scattered by the rock. Low reflectance indicates that more energy is absorbed into the rock. Even though CO2, CO and MIRACL lasers have the greatest absorption, they may not be the best candidates for prototype/field applications. The Direct Diode, Nd:YAG and COIL have lower absorption but they have better prototype/field qualities such as durability, portability, downhole energy delivery and lower environmental impact. However, It has been determined that power not wavelength controls rock removal rate. The size of lasers varies from the US Army’s MIRACL which is the size of a small refinery to the Direct Diode laser which is about of the size of a shoe box. The US Air Force COIL has been miniaturized, as part of the airborne laser defense system, to operate inside a Boeing 747. Sandstone, Limestone, Shale, Granite, Concrete and Salt were tested during the course of the research. Rocks can be chipped, melted or vaporized by a laser beam. It is controlled by diverse mechanisms that are function of both the rock properties and the laser parameters. In every rock type tested, the porosity and permeability were increased and the elastic moduli were altered to weaken the rock. This process in primarily due to the creation of microfractures and dehydration of clays. Even though the melted material in the wall of the hole is impermeable, the rock properties behind the melted sheath are improved. ROP as a function of Specific Energy and Specific Power Specific energy (SE) is a measure of the efficiency of the rock destruction technique. In other words specific energy (SE) is the energy required to remove a unit volume of rock and hence it is a critical rock property data that can be used to determine both the technical and economic feasibility of laser oil and gas well drilling. When a high power laser beam is applied on a rock, it can remove the rock by thermal-spallation, melting or vaporization depending on the applied laser energy and the way the energy is applied. The most efficient rock removal mechanism would be the one that requires the minimum energy to remove a unit volume of rock. The specific energy or the amount of energy required to remove a unit volume of rock and is mathematically defined as follows:

347


SE =

Energy Input P = Volume Reoved dV / dt

⎡ kW ⎤ ⎢ cm2 ⎥ second kW kJ ⎦ =⎣ = = 3 cm cm /sec cm3 Where P = Power Input (Watts) DV/dt = Volume Time Derivative (cm3/sec) Hence Specific Energy varies inversely as the efficiency of the laser cutting process. Also Specific power (Power Density) is the power per unit area, Pc, (kW/cm2). ROP is related to specific power and specific energy by Pc / SE (cm/s). The most efficient rock removal mechanism would be the one that requires the minimum energy to remove a unit volume of rock. To increase ROP, techniques that have high specific power and low specific energy should be used.

Above graph shows a comparison of various techniques for rock drilling and boring in terms of rate of penetration, specific power and specific energy. (1) Percussive drills (small holes); (2) Rotary drills; (3) Drill-and-blast tunneling; (4) Raise-and-tunnel-boring machines; (5) Flame jets; (6) Laser spallation; (7) Future laser spallation. Figure above reveals that to increase ROP of rock breaking, one should use techniques that have high specific power and low specific energy. With better laser head and assisting purging system designs, laser drilling would be the next generation drilling system. Secondary effects like melting, re-melting, absorption of the laser energy by the plasma and the plume, etc., reduce the efficiency of laser cutting and are dependant on mineralogy, thermal 348


properties and rock properties. This underlines the need for an efficient debris and vapor removal system. Some important laser drilling research results Many organizations and institutes are carrying out research in laser drilling The following conditions have been varied during the experiments: rock type, time on target (heat input), beam direction (horizontal or vertical), continuous and pulsed, stress orientation, saturation (air, methane, oil, fresh and salt water), lased through drilling mud and fresh water, sample shape and purge assist gas. A few relevant research results are summarized below. 1. The minimum specific energies (energy required to remove unit volume of rock, SE, kJ/cm3) for two typical reservoir rocks tested in the studies are listed in the Table. It is seen that each rock type has a set of optimal laser parameters to minimize SE. Shale samples recorded the lowest SE values as compared with limestone and sandstone samples. One can see that rock removal mechanisms can be changed between spalling and melting through controlling either the specific power or exposure time. Rock Type

Berea

Laser used

Average power W

Specific power W.Cm2

19

2020

712

2.6 (Spalling)

cw

19

2210

780

3.5 (spalling + slight melting)

CO2

12.7

2210

1,745

12.7

3000

2,369

30.0 (heavy melting)

534

4,217

0.52 (spalling)

415

3,280

1.79 (spalling)

330

2,610

262

2,070

3.53 (spalling)

202

1,590

5.54 (spalling)

534

4,217

grat sandstone

Shale

Pulsed Nd: YAG

12.5

Exposure times,s

Specific Energy,kJ/cm3

Beam spot size, mm

0.5

0.5

1.0

6.5 (spalling + medium melting)

2.71 (spalling)

3.6 (medium melting)

2. Study of samples from rock samples drilled with high-power lasers Figure of Petrographic thin section of Berea gray sandstone showing the lased hole and the four concentric alteration zones • Layer–1 is a discontinuous layer. This layer will not be formed if the laser melt is removed before solidification. • Layer-2 is a continuous layer. This layer forms a sheath of petrified silica around the lased hole. The thickness of layer-2 depends upon the silica content of the lased area, the porosity, the power of the laser, and the thermal conductivity of the rock. This layer shows potential for possibly replacing conventional casing steel used in oil and gas wells.

349


• •

Layer-3 is wider than the other three layers. Layer-3 represents a mechanical support to layer-2. Both layers may indeed provide adequate support for oil and gas boreholes. Layer-4 represents the external limit of the laser thermal effect. Crystals are not transformed into other minerals but are instead mechanically deformed and slightly burnt.

Fresh rock

Layer-4 Layer-3

Layer-2 Layer-1 Lased-hole

3. Overlapping multiple small laser beams method to drill large diameter and deep holes. • To cover large diameter area (8-1/2 or greater), either the small spot size beam has to be scanned or multiple such beams are overlapped.

• • •

Each laser beam can spall a shallow hole as big as the spot size usually 1.27 cm in diameter. Since some relaxation time is needed for avoiding melting of rock, the overlapped beams will fire on the rock sequentially or in groups to create a layer of nearly circular work face of a desired diameter. The rock fragments from this layer will be instantaneously removed with the help of the purging and flushing system.

350


• • • • • • • • •

Then laser beams will fire again to spall the second layer of rock. Layer by layer, a deep hole will be drilled out until the desired depth reaches Laser parameters can be controlled very precisely to achieve spallation, melting or vaporization the rock, depending on the application required. The phase change in the rock depends mainly on; the rock type, thermal properties and measured average power Tests on Nd:YAG laser shows that; Nd:YAG laser can perforate the rock as efficiently as the other types of high power lasers the permeability of the rock lased by pulsed Nd:Yag laser beam increases up to 566% compared to non-lased rocks due to clay dehydration and micro-fractures induced by the high temperature gradient.

Linear Nd:YAG Laser Track Test Samples with Constant Focal Position Change Rate for Sandstone, Limestone and Shale Identifying Laser-Rock Reaction Zones and Calculated Power Densities.

351


Summary of Other Experimental Results • Measured SE increases very quickly with beam exposure time indicating the effects of energy consuming secondary processes. • Temperature higher than 6500C (12000F) was recorded on the tested rock that was exposed to a kilowatt level laser beam. • Rates of heat diffusion in rocks are easily and quickly overrun by absorbed energy transfer rates from the laser beam to the rock. As absorbed energy outpaces heat diffusion, temperatures rise to the minerals’ melting points and beyond, quickly elevating SE values. • A laser is able to spall and melt rock through water, although laser energy at these wavelengths is readily absorbed as it passes through the water to the sample. • High power laser-rock interaction tests have proven that lasers can penetrate all rock types including granite, much faster than conventional methods and other non-conventional methods. Laser can also induce fractures in the rocks by thermal expansion. • The application of high power lasers can also enhances rock properties such as permeability and porosity. (Examination of more than 50 lased samples of different rocks - sandstones, limestones, dolomites, shales, and granites indicates this). • A higher percentage of quartz in the sample will result in higher melting point for the rock, therefore requiring more energy to melt and more energy to vaporize. • Rock properties (type, porosity, moisture content, etc.) effect laser drilling effectiveness and some rocks may have optimum (minimum) SEs higher than others, the consequence of which is slower drilling. • Sandstones saturated with water spall faster. More rock can be removed before melting commences. • Applying 5.34 kW Ytterbium-doped multiclad fiber laser on multiple samples of granite, cement and steel confirmed that the laser was capable of penetrating these materials under a variety of conditions. • Operating a high power laser in underbalanced conditions showed the laser’s ability to perform at downhole conditions without requiring a supplemental assist purge system Conclusions • Laser spallation shows 8 –100 times faster ROP than that of the conventional rock breaking techniques because it has specific power as high as that of flame jets which is the highest among the conventional methods and specific energy as low as that of most conventional methods. • As it drills, the laser exposure creates a glass or ceramic liner that, potentially, could replace the steel casing now required in boreholes. Eliminating the need for casing & drill-pipe would be a big saving. • The most energy efficient drilling can be achieved by maintaining laser intensities below the threshold for rock melting and vaporization. • In narrow, deep holes, fragments of rock can block the beam, wasting energy. Multiple holes drilled side by side with 1-inch-diameter collimated beams for a drill hole diameter of 8 inches overcomes this problem. • Super-pulsed (SP) CO2 laser beams were shown to efficiently drill deep, large diameter holes in petroleum rocks due to peak power 4 times higher than the average power, and the beam’s pulse nature. The SP mode is more efficient than CW operation. • Pulsed lasers cut faster & with less energy than continuous wave lasers. They have better penetration and fracturing, while a CW laser, which dumps too much power into the rock, causes it to melt and vaporize. 352


• • •

•

•

• •

Pulsed Nd:YAG laser with fiber optic cable delivery is a strong candidate for laser applications for oil and natural gas wells. The specific energy improves (decreases) with increasing laser intensity to an optimum just below the transition to a melting mechanism, when the specific energy increases substantially. The objective of laser drilling is to get the laser beam energy to the rock face. Since traditional drilling fluids (mud) used for pressure control and cutting removal are not transparent to laser wavelength, drilling must be done with a transparent fluid. For the initial application, it is anticipated that pressure control and cutting removal would be accomplish using a highpressure inert gas such as N2 or CO2. This is not new technology, since the petroleum industry has used compress gas as drilling fluid for many years. Placing of laser energy downhole i.e. beam deliverability, is the current challenge of research teams. They are currently looking at fiber optics, hollow fibers, fiber lasers, and one of the most promising is the Direct Diode Laser which is compact enough to put the entire laser mechanism downhole. In the lab researchers have successfully drilled more than 18 inches which was limited by sample size available and laboratory capabilities. They have drilled 8 inches diameter hole in the laboratory with a megawatt laser and 0.5 inch diameter hole with a few kilowatts. There is no limit to the size and depth of the hole. It is just a function of the power available. Lasers can be used for perforating or extended reach drilling. The fundamental principles of laser rock destruction are independent of the application. The configuration of the surface and downhole equipment will have to be adapted to the application. Characteristics of the laser system make it friendlier to the environment than current stateof-the-art drilling systems. Laser drilling is faster so the system is on location for a shorter period of time, thus minimizing interruptions to the natural ecosystems and reducing drilling objections for local residents. It is envisioned that the laser system would have a smaller environmental footprint and the use of hazardous chemical would be greatly reduced.

Some of the challenges still being faced by the researchers are; • To apply the technology in actual downhole temperature and pressure conditions, down to where formation fluids are present and mud is used as a fluid for cuttings evacuation. • To confirm that the differential pressure between the reservoir pore pressure and the wellbore pressure would provide the means for ejecting the cuttings in under-balanced conditions downhole. • To make available lasers which can produce more high power to cut different types of rock. The recent evolution of a high-power 5.3 kw ytterbium doped, multiclad fiber laser has raised hopes.

353


Diagram of a high power fiber laser (Courtesy of IPG Photonics, Inc.) • To devise methods to cool the laser head under the downhole conditions and the expected working temperatures (~6000C or more). • To design a laser head that could put the power directly into the well bore and could incorporate a sensor array for real-time monitoring down the hole. This type of precision and range could eliminate many of the side-tracking and directional (lateral) drilling problems. • To deliver power from Nd:YAG and fiber lasers through fibre optics to depths of 2000 M and more. • To fabricate fibre optic cables for the depths required • To determine & address the power loss issues • To built a working laser drilling prototype. Researchers expect that would be ready by 2010. Currently options are being explored to develop a prototype drilling system using the Solid State Direct Diode Laser (DDL) and integrating the various components such as; pressure control, solids removal. Beam deliverability, etc • And finally to incorporate the laser technology and fiber optics with coiled tubing. The laser drilling prototype may provide answers to many of these challenges.

354

References

REFERENCES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25.

Drilling Operations Manual, IDT, ONGC, Dehradun, 1987 Operation and Maintenance Manual, BHEL Oil Well Drilling Rig, Vol. IV Offshore Technology, Unit-V, Lesson-IV, The Hoist, PES The University of Texas, Texas. Drilling Operations Manual, IDT, ONGC, Dehradun, 1994. Rotary Drilling Series, Unit-II, Lesson –III, Drilling a Straight hole, PES, The University of Texas, Texas. Tool Pushers Course Materials, IDT, ONGC, Dehradun, Rabia H., Oil well Drilling Engineering- Principle & Practices, Graham and Trot man London. Rabia H, Fundamentals of Casing Design, Graham and Trotman London Moore L Preston, Drilling Practices Manual, Pennwell books, Pennwell Publishing Company, Tulsa Oklahoma Rotary Drilling Series Unit - I, Lesson –II, The Bit, PES, The university of Texas Texas. Rotary Drilling Series, Unit-I, Lesson –III, The Drill Stem PES, The University of Texas,Texas. BHEL Manufacturing Catalogue Trichi OISD Standard -187 “Care and Use of Wire rope”, MOPNG, Govt. of India, 7th Floor, New Delhi House, 27, Barakhamba Road, New Delhi -110001. Rotary Drilling Series, Unit-I, lesson –V, ‘The Block and Drilling Line’ PES, The University of Texas, Texas. IADC, Houston, Texas. Well Control Manual, IDT, Dehradun, 2003 API-RP 7G (Sixteenth Edition August 1998) Trouble free drilling Vol.-I Stuck pipe prevention by John Metchill Dulberg, Engineering Inc. Stuck pipe prevention, Randy Smith, USA. Stuck pipe prevention Prentice Training Company Inc, Rotary Drilling Series, Unit –II, Lesson –IV, Casing & Cementing PES, The university of Texas, Texas. Operations Manual Halliburton Services, Duncon, Oklahama Coring Manual Diamant Boart Petroleum Division Brussels ( Belgium) Composition and Properties of Drilling Fluids” Darley HCH and Gray G.R. Drilling Fluids Engineering Manual, Magcobar division Oilfield Products Group Dresser Industries Inc. Houston, Texas.

BIBLIOGRAPHY 1. McCray A.W and Cole F.W., Oil Well Drilling Technology, The English Book Depot, Dehradun. 2. Do’s and Don’ts for Drilling Engineers, IDT, ONGC, Dehradun. 3. Gatlin Carl, Petroleum Engineering Drilling & Well Completion, Prentice hall, Inc. Englewood Cliffs, New Jersey.

355

ABOUT THE AUTHORS z

V CHAKRAVARTY : He is B E (Mechanical Engineering) and has 25 years field & R&D experience in ONGC. He has vide field experience in drilling operations in Bombay Offshore and on the Land Rigs.He remained a regular faculty for Drilling Technology courses and specializes in the latest advancements. He has many papers to his credit. He has also authored many OISD standards.

z

R SHANKER : He is B E (Mechanical Engineering) and has wide experience in ONGC.He has field experience in drilling operations in Eastern and Western Region. He remained a regular faculty for Drilling Technology courses. He has presented many technical papers in various workshops/seminars and also authored many OISD standards.

z

D DASGUPTA : He is B E (Mechanical Engineering) and has 13 years of field experience in cementing operations in Agartalla, Assam and Karaikal. He is presently Head of Cementing and Cementing Material (CCM). He is a faculty for Cementing Technology topics.

z

A K JOSHI : He is M Sc (Chemistry) and joined ONGC in 1980. He has working experience as mud engineer on drilling rigs in Assam and Ankleshwer Assets. He is working in R & D section in Drilling Fluid Engineering (DFE). He has many papers to his credit. He is a regular faculty for the drilling fluid related topics.

z

R P AGGRAWAL : He is B E (Mechanical Engineering) and joined ONGC in 1982. He has working experience in drilling operations & directional drilling at various field of ONGC. He has worked in R & D Drilling in directional drilling. He remained a regular faculty for Drilling Technology courses.

z

P K DUBEY : He is B E (Mechanical Engineering) and joined ONGC in 1982. He has working experience in drilling operations in Assam and directional drilling in Ankleshwar. He has worked in HRD and QHSE audit in IDT and his present assignment is Drilling R & D in directional drilling. He specializes in QHSE. He is a regular faculty for Drilling Technology courses.

z

SANJAY KULKARNI : He is BE (Mechanical Engineering) and has varied experience of 24 years of working in the ONGC. He has worked on Jack up rigs as Driller / Tool Pusher at Bombay Offshore for 12 years. He remained a regular faculty for Drilling Technology courses.

z

AJEETH X PARAPULLIL : He is BE (Mechanical Engineering) and has varied experience of 21years of working in the Oil Industry. He has worked on Jack up/Floater Rig as Driller / Tool Pusher for 10 years. He has also worked as Drilling Superintendent on Deep Exploratory High Pressure Gas Well for many years on the Land Rigs.

z

VINOD KUMAR : He is B E (Mechanical Engineering) and joined ONGC in 1988. He has working experience in drilling and cementing operations in Bombay Offshore and Assam assets. He has also worked as Safety Auditor, accredited to DNV, Singapore. He is presently posted in Drilling Technology School and is a regular faculty for Drilling Technology courses.

z

ATANU BHATTACHARJEE : He is B E (Mechanical Engineering) and has 18 years field experience in drilling operations in KG and Assam assets. His present assignment is Drilling R &D and specializes in casing design. He is a regular faculty for casing design.

z

T R K SHERWANI : He is BE (Mechanical Engineering) and has varied experience of 22 years of working in the Oil Industry. He has worked on Land rigs as Driller / Tool Pusher for 15 years. He has also experience of working as Drilling Superintendent on deep wells of Assam Asset & as Fishing Engineer in Ankleshwar Asset. Working as Faculty in Well Control School and Stuck Pipe Prevention courses at IDT, Dehradun

z

G. VENKATSEWARAN : He is BE (Mechanical Engineering) and has varied experience of 21 Years of working in the Oil Industry. He has worked on Floater Rig as Driller / Tool Pusher for 10 years. He has also worked as Drilling Superintendent on Deep Exploratory High Pressure Gas Well for 3 years on the Land Rig. Working as Faculty in Well Control School and other training courses at IDT, Dehradun.

ONGC - Drilling Operation Practices Manual.-2007

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