ENI - Drilling Procedures Manual

ARPO

ORGANISING DEPARTMENT

ENI S.p.A. Agip Division

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

PAGE.

OF

STAP

P

1

M

1

234

6140

TITLE DRILLING PROCEDURES MANUAL

DISTRIBUTION LIST

Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it ) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue:

28/06/99

„ ƒ ‚ • €

Issued by

REVISIONS

P. Magarini E. Monaci 28 / 0 6 / 9 9

C. Lanzetta

A. Galletta

28 / 06 / 99

28/ 0 6 / 99

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

ARPO

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ENI EN I S.p.A. Agip Division

2 OF 234

REVISION STAP-P-1-M-6140

0

INDEX 1.

INTRODUCTION

8

1.1.

Purpose of the document

8

1.2.

implementation

8

1.3.

UPDATING, AMENDMENT, CONTROL & DEROGATION

8

2.

WE W EATHER PREDICTION

3.

DOCUMENTATION

10

3.1.

Reporting 3.1.1. W ell Site Reports 3.1.2. Other W ell Site Reports

10 10 11

3.2.

Co Contractor Performance

11

3.3.

Report Distribution

12

4.

5.

9

SUMMARY OF OPERATIONS (Land Rig or Jack-Ups)

13

4.1.

Conductor Pipe Installation 4.1.1. Pile Hammers 4.1.2. Final Refusal Depth 4.1.3. Conductor Pipe Connections 4.1.4. 30" CP Driving Procedure 4.1.5. Drilling And Cementing CP

13 13 18 19 23 30

4.2.

Drilling 26" Hole 4.2.1. Cl Cluster W ells 4.2.2. Single W ell 4.2.3. Single W ell Using Pilot Hole Technique

31 31 32 33

4.3.

Drilling 17 17 /2” Hole

4.4. 4.5.

1

34

Drilling 12 12 /4” Hole

1

36

Drilling 8 /2” Hole

1

37

4.6.

RUNNING OF 7” CASING

37

4.7.

RUNNING OF 7” LINER

38

4.8. 4.8.

Dril Drilli ling ng Slim Slim Hole Hole (5 /8” or 6”)

38

4.9.

General GUIDELINES

38

7

4.10. Top Drive Drilling SystemS 4.10.1. Drilling Ahead In HP/HT Formations

40 40

SUMMARY OF OPERATIONS (Semi-Submersible)

43

5.1.

BOP Stack equipment 5.1.1. W ellhead Connector 5.1.2. BOP Rams 5.1.3. Annular Preventer

43 45 45 48

5.2.

Fail Safe Valves

49

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5.2.1. 5.2.2. 5.2.3.

6.

7.

8.

3 OF 234

BOP Control System Subsea Pods Ac Accumulators

0 49 54 54

5.3.

RISER AND DIVERTER SYSTEM 5.3.1. Riser Joints 5.3.2. Riser Coupling 5.3.3. Slip Joint 5.3.4. Tensioning System 5.3.5. Lower Flex Joints 5.3.6. Diverter System

54 55 56 56 56 58 58

5.4.

RUNNING THE BOP ANd RISER SYSTEM 5.4.1. BOP Stack And Riser Preparation 5.4.2. Running The Bop And Riser 5.4.3. Landing The BOP Stack 5.4.4. Testing The BOP Stack

61 61 62 63 63

DRILLING MUD

64

6.1.

General

64

6.2.

Mud properties

64

6.3.

Safety actions

65

6.4.

Drilling with Oil-Based Mud

66

6.5.

Minimum stock requirements

67

TRIPPING AND FILL-UP PROCEDURES

68

7.1.

General PROCEDURES

68

7.2.

Tr Tripping with a top drive

71

7.3.

Flow checkS

71

DRILLING STRING DESIGN/STABILISATION

72

8.1.

ST STRAIGHT HOLE DRILLING

72

8.2.

Dog-Leg And Key Seat Problems 8.2.1. Drill Pipe Fatigue 8.2.2. Stuck Pipe 8.2.3. Logging 8.2.4. Running casing 8.2.5. Cementing 8.2.6. Casing W ear W hile Drilling 8.2.7. Production Problems

72 72 73 73 73 73 73 73

8.3.

HOLE ANGLE CONTROL 8.3.1. Packed Hole Theory 8.3.2. Pendulum Theory

75 75 76

8.4.

DESIGNING A PACKED HOLE ASSEMBLY 8.4.1. Length Of Tool Assembly 8.4.2. Stiffness 8.4.3. Clearance 8.4.4. W all Support and Length of Contact Tool

76 76 76 78 78

8.5.

PACKED BOTTOM HOLE ASSEMBLIES

78

8.6.

PENDULUM BOTTOM HOLE ASSEMBLIES

80

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9.

10.

0

8.7.

REDUCED BIT WEIGHT

81

8.8.

DRILL STRING DESIGN

82

8.9.

BOTTOM HOLE ASSEMBLY Buckling

85

8.10. SUMMARY RECOMMENDATIONS FOR STABILISATION

87

8.11. OPERATING LIMITS OF DRILL PIPE

89

8.12. GENERAL GUIDELINES

90

DIRECTIONAL DRILLING

91

9.1.

TERMINOLOGY AND CONVENTIONS

91

9.2.

CO-ORDINATE SYSTEMS 9.2.1. Universal Transverse Of Mercator (UTM) 9.2.2. Geographical Co-ordinates

93 93 94

9.3.

RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT 9.3.1. Horizontal Displacement 9.3.2. Target Direction 9.3.3. Convergence

96 96 97 97

9.4.

HIGH SIDE OF THE HOLE AND TOOL FACE 9.4.1. Magnetic Surveys 9.4.2. Gyroscopic Surveys 9.4.3. Survey Calculation Methods 9.4.4. Drilling Directional W ells 9.4.5. Dog Leg Severity

CORING

98 99 1 01 103 105 110

112

10.1. CORE BARREL TYPES AND USES 10.1.1. W ireline 10.1.2. Ma M arine Core Barrels 10.1.3. Rubber Sleeve 10.1.4. Conventional Core Barrel 10.1.5. Inner Tubes 10.1.6. Modified Barrels

112 112 112 1 12 112 114 114

10.2. GENERAL GUIDELINES

116

10.3. CORING PROCEDURES 10.3.1. Operating Instructions 10.3.2. Preparing for Coring 10.3.3. Starting of the Coring Operation 10.3.4. Possible Cause Of Pump Pressure Changes 10.3.5. Breaking Core (Making A Connection Or Pulling Barrel) 10.3.6. Re R ecovery of the Core

117 117 118 119 12 0 120 121

10.4. Coring In Deviated Holes 10.4.1. Stabilisation of the Outer Barrel 10.4.2. Stabilisation of the Inner Barrel 10.4.3. Stabilisation of the Drill Collar Assembly

123 123 123 123

11. LE LEAK OFF TEST PROCEDURE

12.

4 OF 234

124

11.1. TEST PROCEDURE

125

CASING RUNNING AND CEMENTING

128

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13.

14.

5 OF 234

0

12.1. Responsibilities 12.1.1. Casing Check List 12.1.2. Preparation For Casing Running And Cementing 12.1.3. Installation Patterns (For Mechanical Cementing Aids) 12.1.4. Preliminary Operations 12.1.5. Running Procedure 12.1.6. Casing Operations With A Top Drive

128 129 129 133 137 138 140

12.2. CRA CASING OPERATIONS 12.2.1. Preliminary operations 12.2.2. Handling and running CRA tubulars

140 141 141

12.3. CEMENTING AND DISPLACEMENT PROCEDURE 12.3.1. Single Or First Stage 12.3.2. Dual Or Second Stage 12.3.3. Double Stage Cementing In Deep Wells

143 143 147 150

12.4. Mudline Suspension Procedures 12.4.1. Cementing 20" Surface Casing (With Inner Strings) 12.4.2. Cementing Casings With Plugs

151 151 152

12.5. Post-Cementing Operations

152

12.6. Squeezing

153

12.7. LINERS 12.7.1. Preliminary Preparations 12.7.2. Running And Setting 12.7.3. Cementing

154 154 155 156

LOGGING

157

13.1. Logging While Drilling (LWD) COnsiderations 13.1.1. Advantages Of Using LWD 13.1.2. Onshore Planning 13.1.3. Rig Planning 13.1.4. Contractor Advanced Knowledge 13.1.5. Rig Monitoring System Requirements 13.1.6. Shock Mechanisms That Can Cause Lwd Tool Failure: 13.1.7. Solutions To Shock Problems:

157 157 157 158 158 158 158 158

13.2. Wireline logging 13.2.1. General Guidelines 13.2.2. Preparations 13.2.3. Quality Control 13.2.4. Handling Explosives 13.2.5. Handling Radioactive Sources 13.2.6. Logging Tool Fishing (overstripping method)

159 159 160 160 161 162 163

WELL ABANDONMENT

165

14.1. Temporary Abandonment 14.1.1. During Drilling Operations 14.1.2. During Production Operations

165 165 165

14.2. PERMANENT ABANDONMENT 14.2.1. Plugging 14.2.2. Plugging Programme 14.2.3. Plugging procedure

166 166 166 167

14.3. Casing cutting/retrieving 14.3.1. Stub Termination (Inside A Casing String)

168 168

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14.3.2.

15.

16.

0

Stub Termination (Below A Casing String)

SURFACE WELLHEAD 15.1.1.

6 OF 234

PRELIMINARY CHECKS

168

169 169

15.2. BASE FLANGE INSTALLATION 15.2.1. Welding Procedure 15.2.2. Safety 15.2.3. Pressure Testing 15.2.4. Slips Installation 15.2.5. Casing Preparation 15.2.6. Primary And Secondary Packing Installation 15.2.7. Casing Spool Installation

169 169 171 171 171 172 172 173

15.3. RECOMMENDED FLANGE BOLT TORQUE 15.3.1. Slips Installation 15.3.2. Casing Preparation 15.3.3. Primary And Secondary Packing Installation 15.3.4. Tubing Spool Installation 15.3.5. Primary And Secondary Packing Group Test

174 177 177 177 178 179

15.4. COMPACT WELLHEAD

189

15.5. MUDLINE SUSPENSION 15.5.1. General Guidelines 15.5.2. Temporary Abandonment Procedure.

193 196 200

DRILLING PROBLEMS

201

16.1. STUCK PIPE 16.1.1. Differential Sticking

201 201

16.2. STICKING DUE TO HOLE RESTRICTION

202

16.3. STICKING DUE TO CAVING HOLE 16.3.1. Sticking Due To Hole Irregularities And/Or Change In BHA

203 204

16.4. OIL PILLS 16.4.1. Light Oil Pills 16.4.2. Heavy Oil Pills 16.4.3. Acid Pills 16.4.4. Free Point Location 16.4.5. Measuring The Pipe Stretch 16.4.6. Location By Free Point Indicating Tool 16.4.7. Back-Off Procedure

205 205 205 206 206 207 207 208

16.5. FISHING 16.5.1. Inventory Of Fishing Tools 16.5.2. Preparation 16.5.3. Fishing Assembly

209 209 210 212

16.6. FISHING PROCEDURES 16.6.1. Overshot 16.6.2. Releasing Spear 16.6.3. Taper Tap 16.6.4. Junk Basket 16.6.5. Fishing Magnet

212 212 213 213 214 214

16.7. Milling Procedure

214

16.8. Jarring Procedure

216

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17.

7 OF 234

LOST CIRCULATION

0

217

17.1. Loss PREVENTIVE MEASURES 17.1.1. REMEDIAL ACTION (WHILE DRILLING)

217 218

17.2. Use of DOB AND DOBC PILLS

218

17.3. REMEDIAL ACTION (WHILE TRIPPING)

219

17.4. Use of LCM PILLS

219

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1.

INTRODUCTION

1.1.

PURPOSE OF THE DOCUMENT

The purpose of this manual is to define Eni-Agip Division and Affiliates policies and procedures for general drilling operations. These are based on the contents of the ‘Drilling Design Manual’. The purpose of the manual is to guide technicians and engineers, involved in Eni-Agip’s Drilling world-wide activities, through the procedures and the technical specifications which are part of the corporate standards. Such corporate standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the corporate Company principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws or particular environmental situations. The final aim is to improve performance and efficiency in terms of safety, quality and costs, while providing all personnel involved in Drilling & Completion activities with common guidelines in all areas world-wide where Eni-Agip operates. 1.2.

IMPLEMENTATION

The policies included in this manual apply to all Eni-Agip Division and Affiliates operations. All supervisory and technical personnel engaged in Eni-Agip’s drilling, completion and workover operations are expected to make themselves familiar with these and comply with the policies and procedures specified and contained in this manual. 1.3.

UPDATING, AMENDMENT, CONTROL & DEROGATION

This manual is a ‘live’ controlled document and, as such, it will only be amended and improved by the Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis. Locally dictated derogations from the policies and procedures herein shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Off ice have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.

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2.

WEATHER PREDICTION Weather data for rig locations are required to predict rig downtime, the effects on rig moving, towing and establishing the rig on location. During drilling operations, a forecasting service is mandatory in remote areas or where hostile weather conditions may be expected, e.g. tropical storms. Operating in cold water environments requires additional forecasting due to the possibility of experiencing freezing conditions or mobile ice flows. The site-specific information can be obtained from a certified meteorological and oceanographic consulting company. To predict weather conditions, the consulting company must be provided with the well location latitude and longitude or lease block number, the water depth and expected drilling period. The weather information required is wind, wave and current specifics for 80% weather (normal condition), the one year storm, the 10 year storm and the 100 year storm during the given drilling season. Further information may be necessary in particular situations or to meet local regulations.

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3.

DOCUMENTATION

3.1.

REPORTING

3.1.1.

Well Site Reports

It is vitally important that the operation process is fully recorded and documented in a consistent format, therefore, standard feed-back or report forms with relevant filling instructions for ensuring a consistent and homogeneous method will be used in technical data reporting of world wide activities. It will be the responsibility of the ENI-AGIP and Affiliates Drilling And Completion Supervisor to ensure the correct filling in and forwarding of the appropriate forms/reports to the Company Base (Drilling Manager/Superintendent). The reports necessary for drilling operations are:

• • • • • • • • • • • • •

ARPO ARPO ARPO ARPO ARPO ARPO ARPO ARPO ARPO ARPO ARPO FB 01 FB 02

01 02/A 03/A 03/B 04/A 04/B 05 06 13 20/A 20/B

Initial Activity Report Daily Report (Drilling) Casing Running Report (General Data) Casing Running Report (Job Data) Cementing Job Report (General Data) Cementing Job Report (Job Data) Bit Record Waste Disposal Management Report Well Problem Report Well Situation Report (Well) Well Situation Report (Wellhead) Contractor Service and Equipment Evaluation Contractor Performance Evaluation

Example copies of these reports are included in Appendix A.

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3.1.2.

11 OF 234

0

Other Well Site Reports BOP Sketch

After the BOP stack has been installed, the Drilling And Completion Supervisor shall produce a sketch of the BOP including the size and location of the rams and the depths referred to RKB and send it with the BOP Test Report. BOP Test Report

During every BOP test, the Drilling And Completion Supervisor shall prepare a report on the test results. Cement Bond Evaluation from CBL-VDL-CET

In the description of a CBL-VDL or CET, the Drilling And Completion Supervisor shall fill in a report form with the following:

• • •

Cementing job summary Log evaluation Remarks.

This report shall be attached to the copy of the appropriate log considered. Well Test String Sketch

If well testing operations are conducted, every test string shall be recorded in a sketch with the data as listed below, in addition to the general well test data report:

• • • • • • • 3.2.

String schematic Component description Outside diameter Inside diameter Capacity Lengths Depths.

CONTRACTOR PERFORMANCE

There are two forms for the reporting of contractors performance. Report FB-01 is for reporting of malfunctions and f ailures in services and equipment. Report FB-02 is for documenting a contractors performance in relationship to the contract conditions. These should be completed giving an explanation of problems encountered and suggestions for performance improvement. Both of these forms must be completed in a timely manner at the end of the contractor’s operations or at the end of the well, whichever is applicable. Copies of the these reports are included in Appendix A.

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3.3.

12 OF 234

0

REPORT DISTRIBUTION

The following chart details the destination of, frequency and times that reports need to be distributed. Form

Freq.

Period/

Rig

Base

Peit

Arpo

Delay

Cont

Comp

I

R/A

R*/F

R*

Teap

Stap

ARPO-01

Each Rig

Start of activity

ARPO-02/A

Daily

1 Day

I/A

R*

R*

R

R/F

ARPO-03/A

Each Job

With ARPO02/A

I/A

R

R*

R*

F

ARPO-03/B

Each Job

With ARPO02/A

I/A

R

R*

R*

F

ARPO-04/A

Each Job

With ARPO02/A

I/A

R

R*

R*

F

ARPO-04/B

Each Job

With ARPO02/A

I/A

R

R*

R*

F

End of phase

1 Day

I/A

R

R*

I/A

R* R*

ARPO-05 ARPO-06

F

F

On activity

1 Day

I/A

ARPO-20/A

After job

End of phase

I/A

ARPO-20/B

After job

End of well

I/A

R

FB-01

On activity

1 Day

A

R

R*

R/F

FB-02

6 Months

7 Days

I

R/A

R

R*/F

ARPO-13

Legend:

A F I R R*

I

R*

Approve File Issue Receive Receive for relevant action Table 3.A- Report Form Distribution Chart

Others

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4.

SUMMARY OF OPERATIONS (Land Rig or Jack-Ups)

4.1.

CONDUCTOR PIPE INSTALLATION

Conductor Pipe (CP) is necessary to provide a riser and flow path for drilling mud from the well to the surface pit system. The outside diameter and the wall thickness of conductor pipe should be chosen according to previous experiences in the area and the selected casing profile. 30” OD x 1”. wall thickness Fe42C has been selected as the Eni-Agip Division and Affiliate’s standard for world-wide exploration and development drilling activities, only if this CP is unsatisfactory should alternatives be considered. CP can be installed either by driving with a pile hammer or by pre-drilling a hole and cementing. 4.1.1.

Pile Hammers

Diesel pile hammers (Refer to figure 4.a) are used for surface driving operations on conductor pipe. The driving depth of the conductor pipe is a function of the sediments in the ground. The most common used system is the ‘Delmag - D44 or D46’ which has a hammer weight of 18t with a variable delivery fuel pump. table 4.a, shows the specifications of others types of Delmag Hammers. The Manufacturer's Operating Procedures must be followed when planning driving operations. table 4.b, shows the normal and maximum blows/ft for different CPs and different hammer sizes.

Model D 22 D 22-02

Energy E (ft lbs)

Ram Weight Wr (lbs)

Hammer Weight Wh (lbs)*

Blows/Min

EWh

39,700

4,850

11,200

42 - 60

3.6

4,850

11,400

38 - 54

4.3

24,500 - 48,500

D 30

23,800 -54,250

6,600

12,300

39 - 60

4.2

D 30-02

33,700 - 66,100

6,600

13,150

38 - 54

4.8

D 36-02

38,000 - 83,100

7,900

17,700

37 - 53

4.7

D 44

43,500 -87,000

9,500

22,300

37 - 56

3.9

D 46-02

48,400 - 105,000

10,120

19,900

37 - 53

5.3

D 55

62,500 - 117,000

12,100

26,300

36 - 47

4.4

D 62-02

78,000 - 162,000

14,000

17,900

35 - 50

5.8

* This is without any accessories - Add approx 25% of the total weight for accessories. Table 4.A - Delmag Diesel Hammer Specifications

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Figure 4.A- Typical Diesel Pile Hammer

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Pipe Size And Wall Thickness 20 x .312 20 x .375 20 x .500 20 x .750 20 x 1.00 24 x .500 24 x .625 24 x .750 24 x 1.00 26 x .500 26 x .750 26 x 1.00 30 x .500 30 x .625 30 x .750 30 x 1.00 36 x .500 36 x .625 36 x .750 36 x 1.00 *48 x .750 *48 x 1.00 *

15 OF 234

Blows Per ft: Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum

D 22

65 - 70 90 65 - 90 120 100 - 150 160 140 - 180 200 90 - 110 150 100 - 120 170 120 - 150 200 150 - 200 250 100 - 150 200 150 - 180 250 200 - 220 300 150 - 200 250 200 - 225 275 250 - 300 350 300 - 350 400 160 - 210 260 210 - 235 280 260 - 310 360 320 - 360 425

0

Hammer Size D 30

55 - 80 110 100 - 120 140 120 - 150 170 80 - 100 140 90 - 110 160 110 - 140 180 150 - 180 200 90 - 100 170 110 - 150 200 175 - 200 250 100 - 150 200 140 - 175 250 150 - 200 300 200 - 300 350 120 - 170 220

200 - 250 350 250 - 350 400

With adapter

Table 4.B - Blows/ft for Various CPs and Hammers

D 44

100 - 130 150 130 - 160 180 150 - 200 250

120 - 140 160 150 - 170 190 180 - 210 280 170 - 180 200 180 - 200 300

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The Frank’s Hydrohammer is an ‘intelligent hammer’ due to the sophisticated electronic control design. This control system is capable of regulating the energy for each impact. The net energy applied to the pile, which is measured during every blow, is monitored and can be regulated from the maximum to 5% or less. Since the measure of energy is precisely known, the force applied to the pile can be accurately computed. One particularly unique advantage of the Hydrohammer is t he control system’s ability to shut off the ram automatically if the pile starts to run ahead of the hammer in soft soils, e.g. due to:

• • •

The hammer is not positioned correctly on the pile. Stroke rate becoming too high. Blow energy is too high.

Other advantages unique to this hydraulic hammer are:

• • •

It can operate at any angle, even horizontally. It has an optional printer available to produce a report of the piling operation. It can be used onshore or offshore, in air or submerged under water.

and table 4.c shows a Frank’s Hydrohammer Type S-90.

B

E

A

D

C

Figure 4.B - Frank’s S-90 Hydrohammer

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0

S-90 Specifications

90 kNm 66,000ft lbs 3 kNm 2,200ft lbs 50lb/min 8.2 kNm/t 2.8ft lbs/lbs

Max. pile energy/blow Min pile energy/blow Blow Rate (max. energy) PEW Ratio Weights

4.5t 10,000lbs 9.2t 20,300lbs 0.8t 1,800lbs 4.2t 9,300lbs 14.2t 31,400lbs 11t 24,300lbs

Ram Hammer (in air) Flat-bottom anvil Pile sleeve incl. ballast Total weight in air Total weight submerged

Dimensions

Outside Dia. of hammer (A) Length of hammer (B) Sleeve for piles up to OD (C) Length of the hammer with sleeve and ballast (E)

610m 24ins 7,880 m 310ins 915m 36ins 9,900mm 390ins

Hydraulic Data

Operating Pressure Max. pressure Oil Flow Power Pack Hydraulic hose (ID)

17 OF 234

280bar 4,000psi 350bar 5,000psi 220l/min 58gal/min 140KW 32mm 1.25ins Table 4.C - Frank’s S-90 Hydrohammer

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4.1.2.

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0

Final Refusal Depth

The following procedure details the determination of final ref usal depth. 1)

When the driving depth of the conductor pipe is not specified in the Drilling Programme, the final depth of the driving is the ‘ref usal depth’. The refusal value generally used is 1,000-1,100 blows/metre. Local experience could dictate a different refusal value. The driving depth can be predetermined by conducting soil boring analysis. Examine offset well data for depths and potential problems in order to determine if the CP depth is adequate.

2)

The driving depth of the conductor pipe which is specified in the Drilling Programme is established with the following formula: Hi = [df x (E+H) - 103 x H]/[1.03 - df + 0.67 x (GOVhi - 1.03)] where: Hi

=

Minimum driving depth (m) from seabed

E

=

Elevation (m) distance from bell nipple and sea level

H

=

Water depth (m)

df

=

Maximum mud weight (kg/l) to be used

GOVhi =

3

integrated density of sediments (kg/dm /10m)

If the refusal depth does not meet this value, internal washing may be required. CP internal washing might be necessary several times before reaching the planned depth. 3)

It should be noted that if there is a high refusal value in very hard formations, the CP shoe could collapse.

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4.1.3.

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Conductor Pipe Connections

Conductor pipe joints installed on land rigs, are usually connected by welding bevelled prepared ends of the pipes together. This is a time consuming operation that requires an average of three hours per joint. On a Jack-up, to reduce the time of the operations and when it is practicable, driveable threaded quick connectors (i.e. the RL-4) and driveable squnch joint connectors such as the Fast Realising Joint (i.e. the ALT-2), should be used. a)

A Squnch Joint (Refer to figure 4.c) is a threadless automatic mechanical lock/release connection that makes up without rotation. The extremely strong weight-set connection is well suited for connecting large diameter conductor joints, and connecting the casing to the wellhead housing extension. The type ALT-2 (Refer to table 4.d) heavy-duty squnch joint is used for pipe joins generally up to 36” OD, but larger sizes are available. It is easily stabbed, driveable, reusable and can be released mechanically. It is suitable for the severest conditions above the mud line and can be used below the mud line when the conductor is driven into place. The 20” ALT-2 is an ideal highpressure housing extension connector, with an internal pressure rating of up to 5,000psi. The type ST-2 standard duty squnch joint (Refer to table 4.d) is not a driveable connector. It is used to connect pipe joints up to 30” OD, and is run into a pre-drilled hole and cemented in place. It is recommended for use above the mud line and is reusable and mechanically released.

b)

The Quick Thread Connection RL-4 (Refer to Table) is a very rigid connection for conductor and casing connections and requires just one-quarter turn for full make up. The helix angle of the patented, interlocking thread form, in combination with other connector geometries creates a preload force between the pin and box. The 30” and larger RL-4 conductor connectors have a generous shoulder for ef ficient driving. Four identical threads 90° apart make-up simultaneously. The thread interface is tapered at 4” per ft of diameter. The connector box has four slots cut on the OD, close to the shoulder of the box and the connector pin has four recessed grooves cut on its OD adjacent to the slots on the box. To activate the anti-rotation tab, a 90° incision is made with the impact tool into the anti-rotation slot. A strip of metal is bent into the recessed groove in the pin which provides a positive mechanical lock. It does not need power tongs for make-up and is releasable and reusable. It has a high 9° stab angle with dual stab guides. A negative 5° backrake thread interlock reduces belling tendency. The standard specifications for some selected pin and box sets are shown in table 4.d.

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Table 4.D - Squnch Joint Connectors (continued)

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Squnch Joint

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Quick Thread Connector

Broad Shoulder For Heav Drivin

Positive Stop Load Shoulder (Drive Shoulder) Stab Guide

Two-Step Contured Nose For Easy Stabbing

O - Rin Seal On

O - Ring Seal On Box (Two O - Ring Seals May Be Used For Improved Fatigue Resistence)

Self-Energizing, Single Load Shoulder Snap Ring For Fast, Positive Makeup Release Port 9° Stab Angle

Anti Rotation Pin/Slot

Wide Elevator Shoulder For Easy Handling Stab Guide

Elevator Shoulder

Figure 4.C - Squnch Joints and Quick Connectors

Pipe OD (ins)

Pipe Wall Connector Connector Tension Thickness OD ID Capacity (ins) (ins) (ins) (kips)

Bending Capacity (kips ft)

Internal Pressure (psi)

Weight Pin & Box (lbs)

30

1.00

31.63

27.50

4,600

2,800

4,670

625

36

1.50

36.81

31.75

10,000

5,250

3,900

1,000

38

2.00

39.50

31.10

13,500

12,000

4,000

2,300

42

1.00

43.63

39.50

7,063

4,730

2,300

1,523

Table 4.E - RL-4 Rapid Lock Conductor Connector Standard Specifications (For Selected Pin and Box Sets)

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30" CP Driving Procedure Material Requirements

The following materials shall be available on the rig upon arrival on location:

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

30" conductor pipes as per the Drilling Programme (squnch joints, rapid lock connectors or welded preparation). Pile hammer. Equipment for handling joints. Welding machine, if using welded connections. 26" bits. 26" stabs as per the BHA program. 20" casing. 20" casing equipment (shoe, etc.). Plate for 5" DP (inner-string). 20" cementing plug (for emergency). 20" circulating head. 1 17 /2” bits. 1 17 /2” stabs as per BHA program. 1 12 /4” bit and stabs for pilot hole, if necessary. Sufficient cement for a 20" cementing job. Material for light slurry, if needed. Mud materials enough to drill a 26" hole, plus materials for mixing kill m ud. LCM materials. Sealing adapter assembly for 20” casing cementing job (with 20" 5" DP centralisers). Wellhead equipment for 20" casing.

If quick joint is to be used, the following equipment shall be available:

• • • •

Hydraulic tong 30” type Joy AA -X. Two hydraulic clamp 30” 250t. Side door elevator. Hydraulic power unit.

During the installation of the drilling rig, the following operations shall be carried out: 1) 2)

Inspect materials as per the above list. Mixing mud (this operation is to be started as soon as the rig is in operating condition).

3)

Rig up for driving operations on the 30" conductor pipe.

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Running Procedure, if a quick joint system is used:

1)

2) 3)

The length of each joint will be 12-15m (40-50ft) approximately, unless using nono standard specification. The driving shoe shall be built as per figure 4.d with a 45 internal bevel on the lower end. Each joint will be lifted on to the rig floor with a side door elevator, 30” x 150t. Each joint will be run in hole with a hydraulic clamp, 30” x 250t.

4)

The casing string will be hung of on the slips with a hydraulic clamp, 30” x 250t.

Running Procedure, if a welded joint system is used:

1) 2)

3)

4) 5)

6)

7) 8) 9) 10) 11) 12) 13) 14) 15)

The 30" conductor pipe end has to be checked in order to ensure this is a maximum o angle of 30 for welding operations. The length of each joint will be 12-15m (40-50ft) approximately, unless non standard o specification. The driving shoe shall be built as per figure 4.d with a 45 internal bevel on the lower end. Each joint of CP will have two pad eyes installed appropriately dimensioned and welded 1.5m below the upper end (Refer to figure 4.e ) and one lifting eye welded close to the lower end to permit easy handling with the rig crane. Do not weld on pad eyes if internal or external elevators are available. A 31" false rotary table, to ensure better pipe stabbing, shall be positioned on top of the rotary table (Refer to figure 4.f) The diesel pipe hammer shall be positioned on the rig floor prior to driving operations and all equipment shall be inspected. Every conductor pipe joint shall be measured and marked. Pick up the shoe joint with the travelling block (Refer to figure 4.g), cut and remove the lifting eye, run the joint through the 31" false rotary table. Land the joint on the pad eyes. Pick up the next joint and add to the shoe joint. The connection is obtained by welding the pipe ends. Pick up another conductor pipe with the travelling block, cut and remove the pad eyes on the shoe joint. Lower the string until the conductor pipe shoe reaches the bottom of the cellar or the sea bed, if on a Jack-Up. With the travelling block and the slings, pick-up and stab the pipe hammer onto the last joint. Begin driving operations on the conductor pipe, closely monitoring the first blows as the penetration may be very high. Stop hammering once the pad eyes are about 0.5m above the 31" false rotary table. Do not remove the pad eyes. Remove the pipe hammer. Pick-up the next joint, make the connection, remove the pad eyes and lifting eye on previous joint and continue driving operations. Continue until the planned penetration or the maximum blowing energy is reached (Refer to the Drilling Programme).

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Figure 4.D - Drive Shoe

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Figure 4.E - CP Pad Eyes

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Figure 4.F - False Rotary Table

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Figure 4.G - CP Handling Rig Up

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If the maximum blowing energy is reached before the requested penetration, proceed as follows:

1) 2) 3) 4) 5)

Remove the hammer. Install two pad eyes on the 30” CP joint 0.5m above the spider deck level. Suspend the conductor pipe at rig substructure with four slings. Cut the 30” CP about 1.5m above spider deck level and remove the cut section. Remove the 31" false rotary table.

6)

Run a 26" bit + 3 x 9" DC + HW-DP and wash the conductor pipe down to 0.5m above the present CP shoe. Pull the bit out of the hole. Install the 31" false rotary. Pick up the cut section of conductor pipe and weld it on to the 30” CP string.

7) 8) 9) 10) 11)

12)

13) 14)

Disconnect the suspension slings and cut the pad eyes. Pick up the pile hammer and resume driving operations again until the planned depth is reached. This CP internal washing operation may be repeated several times before reaching the planned depth. Cut the 30" conductor pipe at a specific depth (according to the drilling programme) below the rotary table and install the riser bell nipple and diverter assembly. Lay down the 31" false rotary from the rig floor. Install two pad eyes on the CP just above spider deck level and anchor the conductor pipe with four slings to the rig substructure (if r equired). Jack-up drilling in deep water, often experience problems with conductor pipe tensioning. Normal cables and turnbuckles are not sufficient for the wind, wave, current and temperature conditions which can cause movement when constant tension must be maintained. To resolve these conductor pipe tensioning problems, a multiple hydraulic cylinder tensioning system may be used.

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Drilling And Cementing CP

1)

2)

3)

4)

Run a 26" bit + float valve + 36" Hole Opener + 1 x 9" Monel DC + 1 x 9" Spiral DC + 5" HWDP + 5" DPs; in offshore operations whith Jack-Ups down to the seabed and measure the water depth. Drill to the depth of the first two joints using high viscosity mud (80-120 seconds Funnel viscosity) and at a very slow pump rate, in offshore operation whith Jack-Ups space out in order to avoid pulling the bit above the mud line at the first connection and. Drill the remaining 36" hole down to the a planned depth (with min WOB and at a higher pump rate) pumping fresh water (sea water in offshore operations whith JackUps) and a high viscosity mud cushion (at least 20-30 bbls every connection). Pump mud at a low flow rate if the well doesn't take fluid. At TD circulate the hole clean, displace the hole with gel mud (50% excess over open hole volume) and make a wiper trip; in offshore operations whith Jack-Ups make a wiper trip to the sea bed paying attention not to pull the bit above the mud line.

5)

Run back to bottom. If any fill is found, repeat the previous step otherwise displace the hole with gel mud (100% excess over theoretical hole volume). Take a directional survey and pull the 26" bit + 36" HO.

6)

Run the 30" x 1" thick CP and cement it in the hole using an inner string and sealing adapter (Refer to the Casing Running and Cementing section). Install two pad eyes on the CP just above the spider deck level and anchor the conductor pipe with four slings to the rig substructure, if required. Cut the 30" CP at the specified depth below rotary table according to the Drilling Programme and make up the diverter assembly. Install the bell nipple and diverter assembly.

7) 8) 9) 10)

Run the 26" bit and perform a diverter function test from the driller's panel and remote station as follows: a) Close the diverter around drill pipe and circulate through both diverter lines. b)

Gradually build up to maximum pump rate and record the pressure.

c)

Open the diverter packer.

Note:

If a mud line suspension system is used, Refer to section 12.4.

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4.2.

DRILLING 26" HOLE

4.2.1.

Cluster Wells

1) 2) 3) 4) 5) 6) 7)

8)

9)

10)

11) 12) 13)

14) 15)

16) 17)

18) 19)

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Run a 26” bit and perform a function test; in offshore operations whith Jack-Ups before fill the riser with seawater and check the level. Run the 26" bit + float valve + BHA, specified in the Drilling Programme. Test the diverter function by circulating with drilling water. Test the lines, all relative valves and operating functions. Locate the top of the fill inside the 30” conductor, record and report the depth. Clean out the 30" CP with high viscosity mud at a starting pump rate of 3,000l/m reduced to 500l/m when reaching the proximity of the 30" shoe. Run a ‘Gyroscope’ inside the 30" conductor and perform a directional survey. 1 Run a 26" bit with a 9 /2" Downhole Motor and drill to the 20" casing depth according to the programme, allowing a 9-10 m (30 ft) pocket below the 20" shoe. It is advisable to use the ‘nudging’ hole technique in this phase (max. drift angle is 3°) Start drilling using high viscosity mud with reduced parameters (i.e.: Q = 1000l/m, WOB = 0.3t, rpm = 100-120) for the first two joints, in order to prevent under washing of the nearby casing. Increase the pump rate as per the Drilling Programme down to the planned 26” hole depth. While drilling, the mud viscosity must be kept at high values as per the Mud Programme while keeping the mud density as low as possible. The desilter and desander must be kept in operation. Conduct a wiper trip to the 30" shoe and, if it is good, circulate the hole volume reciprocating the drill string. If an overpull or fill occurs at the bottom, ream the concerned hole section again. Displace the open hole with high viscosity mud (80-100sec Funnel viscosity) and pull out of the hole to run the 20" casing. Take a directional survey as per the ‘Directional Control & Surveying Procedures’. If a pilot hole is required to nudge the hole, due to drillability problems with the 1 formation or to kick-off above the 20” shoe depth, drill the section with a 17 /2” bit and 1 9 /2” drilling turbine. At the 20” casing depth, spot a pill and pull-out. 1 Open the hole to 26” until 9-10m (30ft) of 17 /2” pocket remains. Perform a check trip to the 30” shoe and back to bottom, clean out any fill and spot viscous mud in the open hole section prior to pulling out of hole for running the 20” casing. Pick up enough drill pipe to reach the planned casing shoe depth with stinger and stand back in the derrick. Run the 20" casing, and then run the inner string. Insert the stinger in the casing shoe and circulate for 10 mins max. to test the stinger seals, checking the casing/DP annulus level. Cement the 20" casing as per cementing section. Wait on cement. Remove the bell nipple and diverter assembly, cut and recover the 20" casing above the cellar deck level as per the Drilling Programme.

20)

Weld on the bottom base flange and test it.

21)

As soon as the cement samples are hard, run a ‘Gyroscope’ survey inside the 20" casing from top of the cement to surface. This will be used as the tie-in to any

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previously taken directional survey. Install the high pressure riser drilling spool, BOP stack and test them as per the ‘Well Control Policy STAP P1M6150-7)’. If skidding the derrick for the next hole, cover the previous welded flange with a plate to prevent any objects dropping into the hole.

Single Well

1)

2)

Note:

4) 5)

6) 7) 8) 9) 10) 11) 12) 13)

3

Prior to drilling out the 30” CP shoe, mix approx. 50-60m of kill mud at 1.4 SG to be ready for use if encountering shallow gas; in offshore operations whith Jack-Ups fill the 30” riser with sea water and check the level. Run a 26" bit + float valve + BHA + 1 stand of DP and perform a diverter function test, i.e.: a) Fill up the well with water. b)

Close the diverter around the drill pipe and circulate through diverter lines. Record the time to operate the functions.

c)

Gradually build up to the max. pump rate and record the pressure.

d)

Open the diverter packing. The diverter system is not a blow-out preventer and is not designed to hold pressure, but only to direct flow far from the rig .

Drill the 26" hole down to the planned depth as per the Drilling Programme. Begin drilling with an unweighted gelled mud with reduced parameters (Q = 1000l/m, WOB = 0-3 t, rpm =100-120) for the first two joints, then increase the pump rate as per the Drilling Programme. At 26" hole TD, circulate a volume of mud equal to the capacity of the drilled section. Perform a wiper trip to the 30" shoe and back to bottom again. Clean out any fill and circulate to condition the mud. Take a directional survey with a single shot 10m below the 30" shoe then every 150m to the 26" hole TD. Run and cement the 20" casing as per the Casing Running and Cementing section. Wait on cement. Remove bell nipple and diverter assembly. Cut and recover the 20" casing above celler level or spider deck level In offshore operations whith Jack-Ups as per the rig specifications. Weld on the bottom base flange and test it. Install the drilling spool, BOP stack and test them as per the ‘Well Control Policy STAP P1M6150-7).

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Single Well Using Pilot Hole Technique

1)

2)

3

Prior to drilling out the 30" shoe, mix approx. 50-60m of kill mud at 1.4SG to be used in case of encountering shallow gas; in offshore operations whith Jack-Ups fill the 30” riser with sea water and check the level. Run a 26" bit + float valve + BHA + 1 stand of DP and perform diverter function test: a) Fill up the well with water. b)

Close the diverter around the drill pipe and circulate through diverter lines. Record the time to operate the functions.

c)

Gradually build up to the maximum pump rate and record the pressure.

d)

Open the diverter packing.

Note:

4) 5) 6)

The diverter system is not a blow-out preventer and is not designed to hold pressure, but only to direct flow far from the rig.

Drill out the 30" shoe and circulate to clean out the hole. Pull the 26" bit. 1 1 Run a bit size between 12 /4“ to 17 /2 + Float Valve + BHA. Drill the pilot hole to the 20" casing point with the following procedure: a)

Limit penetration rate to one joint per hour.

b)

Limit pump rate to 1,000l/m for first two joints below the shoe then increase the pump rate as per the Hydraulic Programme.

c)

Stop drilling and monitor for any significant show. Circulate any gas show to surface.

d)

While pulling out of the hole if swabbing occurs, run back to bottom and circulate until control is re-established.

e)

Continually observe returns from the annulus. If there are partial losses, cease drilling and circulate the hole clean before recommencing drilling operations (Refer to loss circulation remedial operations, section 17).

7) 8)

The pilot hole should be 9-10m (30ft) deeper than 20" casing setting depth. Take a directional survey with a single shot 10m (30ft) below the 30" CP shoe and at every 150m (500ft) to TD.

9)

Perform a wiper trip to the 30" shoe and back to bottom again. Clean out any fill and circulate to condition the mud. Pull out of the hole. Run a 26” bit with BHA and enlarge the pilot hole to the casing point and perform a check trip to the 30” shoe then back to bottom. Clean out any fill and spot viscous mud in the open hole section prior to pulling out of hole for running the 20” casing. Run and cement the 20" casing with an inner string as per the Cementing section 12. Wait on cement. Remove bell nipple and diverter assembly. Cut and recover the 20" casing above celler level or spider deck level In offshore operations whith Jack-Ups as per the rig specifications. Weld on the bottom base flange and test it. Install the drilling spool, BOP stack and test them as per the Well Control Policy STAP P1M6150-7).

10)

11) 12) 13) 14) 15) Note:

If a mud line suspension system is being used, refer to section 15.5.

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1

DRILLING 17 /2” HOLE

1)

2) 3) 4) 5)

6) 7)

8) 9) 10) 11)

12) 13) 14) 15)

1

Run a 17 /2 " bit and BHA. Drill out the 20” float collar, cement, casing shoe and wash down to the rat hole TD. If it is planned to drill a long section, install a well head bore hole protector into the base flange. Drill 5m (15ft) of new hole, condition the mud and perform a leak off test (Refer to section 11). 1 Resume drilling with the 17 /2“ bit using the proper BHA for either a vertical or deviated hole (Refer to section 8.1). 1 Drill the 17 /2" hole down to KOP (if in a deviated hole phase) and change the BHA for 1 the build up. If a well is to be vertical, drill the 17 /2" hole to the casing point. Drilling parameters and hydraulics will be in accordance with the Contractor Directional Operator’s instructions (if present) or as per the Drilling Programme. Mud and bits will be as per the Drilling Programme. Take a directional surveys using a MWD tool and/or single shot. 3 At the 13 /8” casing point, circulate the shakers clean. Make a wiper trip to the 20" casing shoe. Run to bottom reaming any tight spots, circulate to condition the mud and pull out of the hole. Run electrical logs as per the Geological Programme. Run a bit to bottom to check the hole, circulate to condition the mud and pull out of the 3 hole to run the 13 /8” casing. 3 Run and cement the single or dual stage 13 /8” casing (Refer to the Casing Running and Cementing section 12). Wait on cement. 3 Hang the 13 /8” casing on the bottom flange giving it additional tensile load calculated as per the ‘Casing Design Manual’ (STAP P1M6110-8.3.4), if required, and cut the 3 13 /8" casing. Pick up the BOP stack. Nipple up the first intermediate casing spool and test it. Lay down the BOP stack. 3 Install the drilling spool, 13 /8” BOP stack and test as per the ‘Well Control Policy STAP P1M6150-7). or install a wellhead protection cap and skid the rig as per the skidding sequence, if drilling cluster wells.

Note:

If a mud line suspension system is being used, (Refer to section 12.4).

Note:

Use the highest grade of 5" DP or HWDP when testing with a cup tester.

table 4.f gives the specifications for Class 1 drill pipe.

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API Units DP (in)

Weight (lbs/ft)

Grade

API Units Max. Tensile Load (lbs)

5

19.5

E-75

395,595

5

19.5

X-95

5

25.6

5

SI Units Rated Load

DP (mm)

Weight (Kg/m)

Grade

SI Units Max. Tensile Load (daN)

Rated Load

316,476

127

29

E-75

176,000

140,800

501,087

400,870

127

29

X-95

223,000

178,400

E-75

530,144

424,115

127

38

E-75

239,900

191,920

19.5

G-105

553,633

442,906

127

29

G-105

246,400

197,120

5

25.6

X-95

671,515

537,212

127

38

X-95

298,800

239,040

5

50.0

HWDP

690,750

552,600

127

74.4

HWDP

307,000

245,600

5

19.5

S-135

712,070

569,656

127

29

S-135

316,900

253,520

5

25.6

G-105

742,201

593,761

127

38

G-105

330,300

264,240

5

25.6

S-135

954,259

763,407

127

38

S-135

424,600

339,680

(80% Load ) (lbs)

Table 4.F - Class 1 Drill Pipe Specifications

(80% Load) (daN)

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1


1)

2) 3) 4) 5)

6) 7)

8) 9) 10) 11)

12) 13) 14) 15)

Note:

1

1

Run a 12 /4” bit and BHA. Drill out the 17 /2” float collar, cement, casing shoe and wash down to the rat hole TD. If it is planned to drill a long section, install a wellhead bore hole protector into the first casing spool. Drill 5m (15ft) of new hole, condition the mud and perform a leak off test (Refer to section 11). 1 Resume drilling with the 12 /4” bit using the proper BHA for a vertical or deviated hole. 1 Drill the 12 /4” hole down to KOP and, if in a deviated hole phase, change the BHA for 1 the build up. If the well is to be vertical, drill the 12 /4” hole to the casing point. The drilling parameters and hydraulics will be in accordance with the Contractor Directional Operator’s instructions (if present) otherwise follow the mud and bits drilling parameters as per the Drilling Programme. Take a directional survey using a MWD tool and/or single shot. 5

3

At the 9 /8” casing point, circulate the shakers clean, make a wiper trip to the 13 /8” casing shoe and then run to bottom reaming any tight spots. Circulate to condition the mud and pull out of the hole. Run electrical logs as per the Geological Programme. Run the bit to bottom to control the hole, circulate to condition the mud and pull out of 5 the hole for running the 9 /8” casing. 5 Run and cement in the single or dual stage 9 /8” casing (Refer to the Casing Running and Cementing section 12.1.5). Wait on cement. 5 Hang the 9 /8” casing on the first intermediate casing spool giving it the additional tensile load calculated as per the ‘Casing Design Manual’ (STAP P1M6110-8.3.4), if 5 required, and cut the 9 /8” casing. Pick up the BOP stack. Nipple up the intermediate casing spool and test it. Lay down the BOP stack. Install the drilling spool and BOP stack and test as per the ‘Well Control Policy STAP P1M6150-7) or install a well head protection cap and skid the rig as per skidding sequence, if on cluster wells.

If a mud line suspension system is being used(Refer to section 12.4).

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4.5.

0

1


1)

2) 3) 4) 5)

6) 7)

8) 9)

Note:

4.6.

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1

3

Run a 8 /2” bit and BHA. Drill out the 13 /8” float collar, cement and casing shoe then wash down to the rat hole TD. If it is planned to drill a long section, install a wellhead bore hole protector into the second drilling spool. Drill 5m of new hole, condition the mud and perform a leak off test (Refer to section 11). 1 Resume drilling with the 8 /2” bit using the proper BHA for a vertical or deviated hole. 1 Drill the 8 /2” hole down to KOP and, if in a deviated hole phase, change the BHA for 1 the build up. If the well is vertical, drill the 8 /2” hole to the casing point. Drilling parameters and hydraulics will be in accordance with the Contractor Directional Operator’s instructions (if present) otherwise the mud, bits and drilling parameters will be as per the Drilling Programme. Take a directional surveys using a MWD tool and/or single shot. 1

5

At the 8 /2” casing point, circulate the shakers clean, make a wiper trip to the 9 /8” casing shoe and then run to bottom reaming any tight spots. Circulate to condition mud and pull out of the hole. Run electrical logs as per the Geological Programme. Run the bit to bottom to control the hole, circulate to condition the mud and pull out of the hole for running the 7" casing. A 7” liner or casing will be run only if required due to drilling problems before reaching the scheduled TD of well or if well tests have to be performed.

RUNNING OF 7” CASING

1) 2)

3) 4) 5)

Run and cement in the single or dual stage 7" casing (Refer to the Casing Running and Cementing section 12). Wait on cement. Hang the 7" casing on the second intermediate casing spool giving it the additional tensile load calculated as per the ‘Casing Design Manual’ (STAP P1M6110-8.3.4), if required, and cut the 7" casing. Remove the BOP stack. Nipple up the tubing spool and test it. 1

Re-install the BOP stack replacing the 5” lower pipe rams with 5” variables or 3 /2” rams and test them as per the ‘W ell Control Policy STAP P1M6150-7).

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4.7.

3) 4) 5) 6) 7)

Check the inside diameter and rated load of the drill pipe. Run the 7” liner checking the weight and circulate the liner capacity after the making up of hanger to check the setting tool seal. Set the liner as per the Manufacturer’s Procedure or as per section 12.7. Cement as per the ‘Casing Running and Cementing’ section 12, pull the stinger out of the liner, circulate out the excess cement and condition the mud. Pull ten stands, circulate and wait on cement. Circulate, pull the setting tool out of the hole using a spinner. 1 Run a 8 /2” bit to the liner top, clean free of cement and circulate. Perform a seal test of liner PBR and pull out of the hole. 1 Replace the 5” upper pipe rams with 3 /2” rams and test the BOP stack as per the Well Control Policy STAP P1M6150-7) 7

DRILLING SLIM HOLE (5 /8” OR 6”) 7

1) 2) 3)

Run a 5 /8” or 6” bit and drill out the cementing equipment in the 7” liner or casing. Drill 5m of new hole, condition the mud and perform a leak of test, if required. 7 Drill the 5 /8” or 6” hole to the planned depth following the specified Mud and Hydraulic Programme.

4)

At TD make a wiper trip up to the 7” casing shoe, run to bottom again and circulate to condition the mud. Pull out of the hole. Run logs as per the Geological Programme.

5) 4.9.

0

RUNNING OF 7” LINER

1) 2)

4.8.

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GENERAL GUIDELINES

1)

All depth measurements will be referenced to RKB (rotary kelly bushing).

2)

A stock of diesel oil, enough for five days of operations, must always be kept on the rig A stock of barite (usually 100t is accepted as the minimum stock level calculated on the basis of the estimated overpressure development, refer to section 6.5) must be kept on the rig all time during drilling operations. BHA equipment and drill pipe must be inspected by non-destructive tests, as specified in the drilling rig contract, by the drilling contractor and any time as required by the ENI-AGIP representative. For severe or particular difficult drilling conditions refer to the ‘Drill String/Bottom Hole Assembly Monitoring Procedures For Severe or Particular Drilling Condition (STAP-M-1-M-5008)’. As a general rule, the following guidelines should be used:

3)

4)

• •

Before the start of the Drilling Contract and every 1,500 rotating hours thereafter, all Drill Pipe bodies shall be ultrasonically inspected. They can be replaced by another previously inspected string to allow the NDT. Heavy weight drill pipe bodies shall be ultrasonically inspected every 3,000 rotating hours. They also may be replaced by previously inspected pipe to allow NDT.

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5) 6)

7)

8) 9) 10) 11) 12)

13)

14) 15)

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Before the start of the Drilling Contract and every 300 rotating hours, thereafter, all drill collars, drill-stem-subs and heavy weight drill pipe thread connections shall be magnetically inspected. They also may be replaced by previously inspected pipe to allow NDT. • All stabilisers shall also be inspected every 300 hours as above. After 200-300 drilling hours (depending on the severity of work) remove four • stands of 5” DP from the top of the BHA and replace them with new ones. The removed DP must be sent to the Contractor’ s workshop for inspection. Five stands of heavy weight drill pipe must be installed between drill collars and drill pipe. A float valve or a flapper valve, preferably the vented type, shall be placed immediately above the bit while drilling pilot holes and larger holes as per the ‘Well Control Policy Manual’ (STAP P1M6150-9.3.1). A vented type allows easy recording of the shut in drill pipe pressure. A kelly cock shall be run both above and below the kelly. If using a top drive system, two inside BOPs; one Hydraulically Remote Operated and one Manually Operated, shall be used. Fishing operations or major changes in the BHA configuration must be discussed first with the operations base and approval obtained. Directional surveys must be performed as per the ‘Directional Control & Surveying Procedures’ Blind or shear rams must be closed every time that tools are out of the hole. Record the distance between the rotary table and the BOPs. 1 1 A 4 /2” IF or 3 /2” IF pin, threaded circulating head, a kelly cock and a chicksan line, must be always present on the rig floor ready for use. For the BOP Testing Procedure, refer to section 5.4.4 ‘BOP and Casing Tests’. The drilling contractor shall be requested to submit a written procedure for BOP testing prepared specifically for the type of equipment installed on the rig, and obtain the Company’s approval before starting operations. When a drilling jar is used, never drill past the last two metres of kelly. This practice allows cocking of the jar if pipe becomes stuck on the bottom. This also applies to top drive drilling systems. All tools run in hole must be measured and recorded for length, ID, OD, and a simple sketch provided and always available on the r ig. When a PDC bit is used to drill out plugs and floating equipment, it is recommended to use a ‘bit saver’ floating equipment and a ‘non rotating plug’ set.

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TOP DRIVE DRILLING SYSTEMS

The Top Drive Drilling System (Refer to figure 4.h and figure 4.i) consists of a drilling drive motor that connects directly to the top of the drill string. The motor, which provides the similar torques and speeds found in most independent rotary drive systems, is mounted to the rig's conventional swivel and is most commonly a DC drilling motor but hydraulic versions are also available. The drill pipe is rotated by the motor through reduction gearing. The swivel attaches to the travelling block and supports the string weight during hoisting operations. A unique pipe-handler system, consisting of a torque wrench and a conventional elevator, assists pipe-handling operations during make up and tripping. The elevator links and elevator are supported on a shoulder located on the extended swivel stem. These systems provide the same power as the rotary table without compromising the efficiency of the conventional hoisting equipment. However they save much time especially in drilling and reaming operations. as described below. 4.10.1. Drilling Ahead In HP/HT Formations

The intention of this procedure is to maintain full pressure control during drilling operations and have the bit as close as possible to bottom in case a kick should occur. At the same time have the kelly valve close to the rotary table in order to carry out jobs which require a tool joint near the rotary table, e.g. installation of high pressure circulation lines, wireline lubricator, etc. The recommended procedure is: 1)

Make-up a kelly cock (15,000psi) to the single in the mouse-hole. The valve is to be in the open position.

2) 3) 4) 5)

Make-up the single onto the top drive. Drill the single and break out above the kelly cock. Pick-up a new single with another kelly cock (15,000psi). Break out and lay down the kelly cock in the string.

Note:

The kelly cock should be tested to the maximum anticipated surface pressure each time it is used.

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Figure 4.H - Typical Top Drive System

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Figure 4.I - Safety Valve Actuator System

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5.

SUMMARY OF OPERATIONS (Semi-Submersible)

5.1.

BOP STACK EQUIPMENT

Floating drilling rigs may be equipped with either a ‘one stack’ or a ‘two stack’ BOP system. The two stack system is a combination of a 2,000 or 3,000psi large bore stack and a 5,000, 10,000 or 15,000psi stack. A one stack system is either a 10,000 or 15,000psi system. The following list gives the common sizes and various configurations: a)

Single stack systems 3

18 /4" - 10,000 and 15,000psi WP 3

16 /4" - 10,000 and 15,000psi WP b)

Two stack systems 1

21 /4" - 2,000 and 3,000psi WP 5

13 /8" - 5,000, 10,000 and 15,000psi WP c)

Configurations 4 rams and 2 annulars 4 rams and 1 annular 3 rams and 1 or 2 annulars 5

The most common configuration consists of a 13 /8" single stack system with 4 rams and 2 annulars (Refer to figure 5.a). This configuration is used in this section as an example to describe BOP equipment bearing in mind that same principles apply to all types. A conventional BOP stack consists of two sections, the lower which contains:

• • •

Wellhead connector Ram preventers One annular preventer

and the upper part which contains:

• • • •

Hydraulic connector Annular preventer Control system pods Flex joint to the top of which the riser is connected.

This upper part is referred to as the lower marine riser package (LMRP), the term stack being applied to the lower part. If it ever needs to be repaired during the course of the well, the package can be retrieved with the riser leaving the stack in position on the wellhead.

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Figure 5.A - Common BOP Stack Arrangement

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Wellhead Connector

The wellhead connector profile must obviously match that of the subsea wellhead. In Eni Agip Division and Affiliates use the most common profiles which are Vetco H4 and the Cameron Collet. 5.1.2.

BOP Rams

Besides being able to seal off the annulus around the drill pipe, the pipe rams can also support the weight of the drilling string if it needs to be hung-off. The maximum hang-off capacity is in the region of 600,000lbs (280t), depending upon ram and pipe size. To hangoff the string securely, the rams must be able to be locked in the closed position without risk of accidental opening. Cameron

The Cameron U-type preventers use a wedge-lock device (Refer to f igure 5.b) to accomplish this feature. It consists of a tapered wedge, hydraulically operated, which moves behind the tail rod of the ram operating piston when the ram is in the closed position. Since it can only move when ram lock pressure is applied and the ram is fully closed, all the ram lock cylinders on the stack are connected to just two common control lines, lock and unlock. Ram lock pressure is activated from the surface as an independent command. A pressure balance system is fitted to each ram lock cylinder to eliminate the possibility of seawater hydrostatic pressure opening the wedge-lock in the event that the closing pressure is lost. Shaffer

On a Shaffer type LWS or SL rams, the locking device is actuated automatically whenever the ram is closed. This is called the ‘Posilock’, this system (Refer to figure 5.c) uses segments that move out radially from the ram piston and lock into a groove in the circumference of the opening cylinder whenever the ram is closed. When hydraulic closing pressure is applied, the complete piston assembly moves inward and pushes the ram t oward the wellbore. With the ram closed, the closing pressure then forces a locking piston inside the main piston to move further inwards and force out the segments. A spring holds the locking piston in this position so that the segments are kept locked in the groove even if closing pressure is lost. When hydraulic opening pressure is applied, the locking cone is forced outward and this allows the locking segments to retract back into the main piston which is then free to move outwards and open the rams. Hydril

On a Hydril preventer the ram lock device, called Multiple Position Locking (MPL), operates automatically through movement of ram pistons.

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Figure 5.B - Cameron 'U' Type Ram Lock Mechanism

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Figure 5.C - Shaffer 'Posilock' Ram Lock Mechanism

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Variable Rams

In order to provide more flexibility and perhaps avoid having to pull the stack to change pipe 1 rams when drilling is to continue with 3 /2" drill pipes, variable bore pipe rams can be used. These are available in a variety of size ranges. They are capable also of being used for hang-off purpose though the weight they can support depends on the size of pipe they are closed around. However, variable bore rams are not recommended for stripping operations or for high temperature application. Blind/Shear Rams

All subsea stacks contain blind/shear rams. These are designed to cut through pipe and then seal off the wellbore completely. For the location of the blind/shear rams and pipe rams refer to Eni-Agip Division and Affiliates Well Control Policy. 5.1.3.

Annular Preventer

When operating any annular blow-out preventer subsea, the hydrostatic pressure of the drilling fluid column in the marine riser exerts an opening force on the blow-out preventer. Therefore, the closing pressure required is equal to the surface installation closing pressure plus a compensating pressure to account for the opening force exerted by the drilling fluid column. On the Hydril GL preventer, which is primarily designed for subsea operations, a secondary chamber is used to compensate for the effects of subsea operations. The area of the secondary chamber is equal to the area acted on by the hydrostatic pressure of the drilling fluid column. The secondary chamber should be hooked up using one of three techniques. Two of the hook up techniques require adjustment of the closing pressure. The third hook up techniques requires the secondary chamber to be connected to the marine riser by mean of a surge absorber, so that the opening force exerted by the drilling fluid column is automatically counter balanced. Choke And Kill Line Outlets

The two or more outlets on the stack are usually referred to as the choke and kill line outlets and is terminology taken from land drilling operations. For floating drilling the functions of each line are interchangeable since they are manifolded at the rig floor to both the rig pumps and the well control choke. For the position of the outlets on the stack, refer to the Eni-Agip Division and Affiliates Well Control Policy in the ‘Well Control Policy Manual’.

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FAIL SAFE VALVES

These valves are usually mounted in pairs on both the choke and kill lines. They are opened hydraulically from the surface (0.6galls of fluid is typically required) but once the opening pressure is released, spring force automatically forces t he gate valve closed. In deep water operations, the hydrostatic head of fluid in the opening line tends to open the valve. Some designs counter this be incorporating a system which transmits seawater hydrostatic pressure to an oil chamber on the spring side of the piston to compensate for this effect. Other designs have separate pressure-assist closing lines, figure 5.d shows a Cameron type AF fail-safe valve. o

Due to space limitation, the innermost valve on the stack is usually a 90 type with a flow target to avoid fluid or sand cutting. The outer valve is normal straight through and must be bi-directional, i.e. able to hold pressure from on top as well as below for testing the choke and kill lines. 5.2.1.

BOP Control System

The simplest form of BOP control is to assign a hydraulic line direct to each individual function. This presents little problem on land rigs where the large number of control lines required can be easily handled and the distance the control fluid has to travel is not great. On a subsea stack, this direct control is impractical, too many individual lines would be needed and the pressure drop inside them would be too great for the reaction time to be acceptable. For this reason, other systems have been developed based on the idea of using one main hydraulic line through which power fluid is sent to the stack and for pilot valves located on the stack to direct it to the various functions on command from the surface. These commands can be easily transmitted to the pilot valves either hydraulically, electrically or acoustically.

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Hydraulic Control Systems

The main components of a hydraulic control system are shown in figure 5.e. A master hydraulic power unit supplies fluid to both pilot and hydraulic lines via accumulator bottles. The stack can be controlled from this unit or from a remote control panel on the rig floor or an electric mini panel usually located in the rig of fice. Pilot and operating fluid is provided to stack via one of two hose bundles each of which terminates in a Pressure Operating Device (conventionally termed yellow or blue pod) mounted on the lower marine riser package. The pods are identical, one providing complete backup for the other, either one being selected for use from the control panels. A typical 3 hose bundle is made up of a 1" supply hose for the power fluid and up to 64 x /16" hoses for the pilot fluid. Inside each pod the pilot lines terminate at pilot valves, each of which is connected to the common power fluid supply. When a particular stack function command is selected, pilot fluid pressure is directed down a pilot line to the corresponding pilot valve. This valve opens to allow the operating fluid to pass through it and then via a shuttle valve to the operating cylinder. The shuttle valves, which are mounted on the stack, allow the fluid to flow to the operating cylinder from the one selected pod only. The operating fluid is stored in the accumulator bottles at 3,000psi. This pressure is too high for normal operation of the annulars or rams and so the control pods contains regulators in order that closing pressure can be controlled as required (usually from 0 to 1,500psi), though higher if the situation demands it. The subsea regulator is controlled from surface via a pilot line and another line returns to a panel gauge and gives the ‘readback’ operating pressure downstream of the regulator. Each control pod is mounted in a receptacle on the lower riser package and can usually be retrieved independently if repairs become necessary. Whilst the stack is being run, the hose bundle is fed out from a power driven reel which is equipped with a manifold so that control of 5 or 6 stack functions can still be maintained during running. Once the stack has been landed and sufficient hose run out, a special junction box on the reel enables a quick connection to be made between the pod and t he hydraulic unit. Some of the hydraulic power fluid is stored in accumulators located on the stack in order to reduce closing times and also to provide a surge chamber effect for the annular preventers. All the operating fluid on the low pressure side of a function is eventually vented to the sea via the pilot valves. This, therefore, necessitates the use of environmentally friendly fluid which must also inhibit corrosion and bacterial growth as well as being compatible with anti-freeze additives. Large volume of fluid are prepared and stored near the hydraulic unit and are transferred automatically to the accumulators by electrically driven triplex pumps whenever accumulator pressure falls below a preset level. The pilot fluid circuit is closed. A turbine type flow meter mounted on the hydraulic unit measures the volume of hydraulic fluid used every time a function is operated. This can indicate for example whether or not a ram is closing fully or if there is a leak somewhere in the system. Apart from the ‘close’ and ‘open’ positions, it is also possible to place a function in ‘block’ position. In this position, the lines carrying pilot pressure to the pilot valves have a vented spring action in the pilot valves which shuts off the power fluid supply and vents both sides of the operating piston.

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Figure 5.D - Fail Safe Valve

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Figure 5.E - Hydraulic Control System

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Electro-Hydraulic Control Systems

The object of the BOP control system is to move sufficient power fluid, at the required pressure, to the operating cylinder in the minimum time possibly. For very long lengths of hose bundles (over 2,000ft or 600m), friction losses inside the small pilot lines result in unacceptably long reaction times. If the diameter of these lines is increased, the hose bundle would be too bulky to handle so an alternative to a purely hydraulic control system is needed for deep water operations. This is satisfied by electro-hydraulic systems in which the hydraulic pilot valves are operated by electrical solenoid valves in the control pods through lines from surface. High pressure is taken from the main power line in the pod under control of the solenoid valve and is used as pilot pressure to open the pilot valve and thus allow regulated power fluid through to the operating cylinder. A further refinement to this system reduces all the separate electrical lines in the hose bundle to only two, down which coded multiplexed signals are transmitted. A multiplex package in the control pod decodes these signals and activates the corresponding solenoid valve. c)

Acoustic Control System

Although in both the control systems described above, redundancy is assured through the use of two identical control pods, a f urther fully independent system is sometimes desired for complete back-up for contingency. To suit this requirement, acoustic control systems have been designed which can operate certain selected vital stack functions even if the rig is forced off location and, therefore, is not physically attached to the wellhead. This system basically uses a portable battery powered surface control unit connected to either a hull mounted or portable acoustic transducer to transmit an acoustic signal to a receiver on the stack. The receiver and the battery powered subsea control unit respond to the signal and transmit a reply back to the surface. A subsea valve package on the stack interfaces the acoustic and primary hydraulic systems via shuttle valves. It contain solenoid valves powered by the subsea battery pack (rechargeable only on surface) and pilot valves. Pilot fluid, provided from a separate pilot fluid accumulator with power fluid, is stored in a separate bank of stack mounted accumulator bottles. These store fluid at 3,000psi and can be recharged via the primary control system. The valve package contains no subsea regulator, hence, the 3,000psi is applied directly to t he operating piston. A secure coded signalling system and noise rejection circuit eliminate the possibility of a function being executed by accident. To improve signal reception on the stack, two subsea transducer are mounted on long horizontal arms which swing down automatically on opposite sides of the BOP stack when it is lowered. The transmission range for such a system is in the order of one mile or 2km.

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Subsea Pods

As already described, the pods contain the regulators and pilot valves required to direct the hydraulic fluid to the various stack functions. The retrievable type is the most commonly used by the industry. The retrievable male portion of the pod contains all the pod valves, regulators and the hose bundle junction box. Should a pod valve, regulator or hose bundle malfunction, it is quicker and, hence, less costly to retrieve the pod than to retrieve the riser and the lower marine riser package. 5.2.3.

Accumulators

Accumulators are used to store hydraulic fluid under pressure. As much accumulator volume as possible is located on the subsea stack in order to reduce operating time and also to enable them to act as a surge chamber for the annular preventers. 2

Surface accumulators are pre-charged with nitrogen to 1,000psi (70kg/cm ). Subsea 2 accumulators should be precharged with nitrogen to 1,000psi (70kg/cm ) + 45psi per 100ft 2 (10.3kg/cm per 100m) of water depth to compensate for the hydrostatic head of sea water. For total accumulator volume refer t o the Eni-Agip Well Control Policy. 5.3.

RISER AND DIVERTER SYSTEM

The riser system provides communication between the wellhead and the rig floor in order for tools to be guided into the well and provide a return path for mud to surf ace. A riser systems consists of a number of elements: a)

Diverter System

b)

Slip Joint

c)

Riser sections

d)

Lower Flex Joint or Ball Joint

e)

Riser Coupling

The most important single parameter in the design and operation of a marine riser is the tension applied at the top of the riser. This tension is provided by a system of pneumatichydraulic pistons attached to wire ropes which are in turn attached to the outer barrel of the slip joint. The tension is conveyed through the outer barrel, into the riser string and down to the ocean floor where it is attached to the wellhead. The slip joint, or telescopic joint, allows the riser to change length as the vessel heaves, as the depth changes due to tides, or when the vessel moves laterally away from t he wellhead. To reduce the bending moments in the riser and, therefore the induced stresses, a lower flex or ball joint is attached to the top of the BOP stack and an upper ball joint, called the diverter ball joint, is located below the diverter on top of the inner barrel of the slip joint.

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The diverter and the diverter ball joint are attached between the underside of the drilling floor and the riser slip joint inner barrel. The drill string and drilling tools are inserted into the riser through the diverter which also contains the flowlines for circulating the drilling mud. All risers have ‘integral’ choke and kill lines. These are permanently attached to the riser joints and recessed into support flanges for protection. Some risers are also fitted with mud booster lines. These enter the riser immediately above the ball joint and are used to increase the velocity of the mud inside the riser when drilling with a relatively slow pump rate. The riser is used to run the BOP stack which weighs several hundred thousand pounds. This is a delicate operation and is usually performed only in calm weather conditions. While running the BOP, the motion compensator cannot be used so the BOP and riser are forced to move in time with heave the of the vessel. Landing the BOP is obviously a delicate task under these circumstances. All telescopic joints, flex/ball joint adapters and riser joints to be run must have a thorough magnaflux inspection of the riser couplings and pipe to coupling welds before being used. The telescopic joint tensioner ring and the riser handling tools should also be inspected by magnaflux. Welding on riser couplings, riser pipe, choke/kill lines or choke/kill line stab subs is strictly prohibited. 5.3.1.

Riser Joints

Riser joints are constructed of seamless pipe, usually 50ft (15m) long, but a selection of pup joints are available so that the total length of the riser can be adjusted to suit any water depth. The pipe material and wall thickness are usually chosen based on the water depth in which 7 1 the vessel will be operating. In shallow water /16" or /2" wall thickness riser made of X-52 1 5 steel is commonly used. Higher strength materials such as /2" to /8" wall X-65 steel are used in deep water to withstand the higher stresses imposed by high riser tensions. Buoyancy can be added to the riser to reduce the tension applied. It is usually added for water depths beyond 1,000ft (300m). With buoyancy added the effective outer diameter of the riser is 38”-44” and, hence increases the amount of storage space required on the rig. High strength risers are also required to reduce the risk of collapsing in deep water applications when it becomes evacuated or filled with gas. One option to prevent this is to insert a mechanical fill-up valve into the riser string which will fill the riser with seawater if it becomes evacuated. There are common riser sizes that correspond to the wellhead system and BOP stack bore size being used. They are classified by their OD, e.g.:

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Wellhead System

0

Riser Outer Diameter

13 /8”

5

16”

3

16 /4”

18 /8”

18 /4”

3

21”

1

24 “

5

21 /4” Table 5.A - Riser Joint/Wellhead Sizes 5.3.2.

Riser Coupling

There are many styles of riser coupling available with different methods for preloading the connector. The most important function of the preload is to maintain rigidity in the joint and preclude mechanical shifting in the presence of alternating bending loads. Alternating loading will cause less stress if the connector is working within the preload region, thus increasing fatigue life. Improper preloading and inadequate maintenance are the main causes of riser failures. 5.3.3.

Slip Joint

The slip joint, or telescopic joint consists of an outer barrel connected to the riser with a polished steel inner barrel connected to the diverter ball joint. Rubber packing elements seal the annular space between the two barrels whilst still allowing the inner barrel to ‘scope’ up and down. The packing is usually actuated by air and/or hydraulic fluid pressure which is adjusted so that a small amount of mud is able to leak past the seal to provide lubrication. Split packings are used so that if a serious wear occurs they can be replaced without having to remove the inner barrel. Some slip joints have dual packers with the second packer being used as a back-up and, while diverting, can be energised to assist in sealing around the inner barrel. The slip joint is rated to the working pressure of the diverter but when the diverter is used it will most likely leak unless the packer pressure has been increased. The telescopic joint is a weak link in the diverter system and needs to be continuously monitored when diverting. A large ring to which the riser tensioner lines are attached is able to slide over the outer barrel and butts against a flange on top of the barrel. When tension is applied the ring bears against the flange to support the riser. 5.3.4.

Tensioning System

Riser tension is provided by a system of hydraulic pistons (tensioners) pressurised by compressed air. Large air accumulators are used to provide a soft spring effect. The air acts against the hydraulic fluid with almost constant pressure so that the tension in the wire rope remains constant over the stroke. From the tensioners the wire ropes run over sheaves and is turned to the outer barrel of the slip joint (Refer to figure 5.f).

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Figure 5.F - Riser Tensioning System

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As the vessel heaves downward, the angle of the wire rope with the vertical grows thus reducing the vertical component of the tension and vice versa when it moves upward. For this reason the sheaves are placed as close as possible to the path of the riser so that the cable will be nearly vertical. Further more the sheaves are pivoted so they can follow the angle of the wire rope as the riser moves about in the moonpool due to the vessel motion. As the wire rope passes over the sheaves on the tensioners, fatigue occurs. At regular intervals, depending on the severity of the sea state, each tensioner must be shut down and the wire line slipped so that the fatigued section is removed. 5.3.5.

Lower Flex Joints

The Flex Joint contains an elastomeric element (consisting of spherical layers of steel laminates and elastomeric pads) which is held in compression and flexes under shear. The advantages of the flex joint over a ball joint is that it requires no lubrication and no pressure balancing. The increased bending moment caused by the stiffness of flex joints causes an insignificant increase on bending stress in the riser pipe. o

The flex joint can deflect in any direction up to a max of 10 . 5.3.6.

Diverter System a)

Diverter System

The subsea diverter system is an integral part of the marine riser system. Diverter mechanism consists primarily of a packing insert that can seal on drill pipe (or open hole with an insert plug), a control system, two flow lines, a ball joint and valving. The Regan (Hughes Offshore) KFD diverter is the most common system used on today's rigs. There are three basic models:

• • •

KFDG (Gimble) which is used on rigs that do not have an upper ball joint. KFDH (Housing) used on many vessels having limited room between the main deck and the rotary floor. KFDS (Seal) which has its housing permanently mounted through or below the rotary beams.

The ‘H’ and ‘S’ models come in reduced bore par or full bore designs. Each of these diverters is rated to 500psi working pressure. The housing on all three of these diverters are restrained from moving upwards by locking dogs or downwards by a shoulder or lower dogs. The diverter is designed to seal on pipe by pressuring up an outer packer which in turn squeezes on an insert packer. Manufacturers do not 1 recommend the closing of the packer on any pipe smaller than 4 /2” diameter. An insert plug should be installed when the pipe is not in the hole. The outer packer may rupture if closed without the insert being in place.

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Ball joint

Most floating rigs utilise an upper ball joint located directly below the diverter. In this position it carries little load and its working tensile load is only the weight of the inner barrel of the slip joint. Due to this reduced operating load, the ball and socket cavity may only need to be packed with grease instead of high pressure oil to lubricate the joint. o

The ball joint operates up to a maximum deflection of 10 and its pressure rating is to the working pressure of the diverter minimum. c)

Diverter Lines and valves

The overboard lines of the diverter system should be 12" or more in diameter in order to minimise back pressure during high flow rates, which is usually a feature of a shallow blow-out. Another feature of a shallow gas blow-out is the large amounts of sand and stones which can be produced. For this reason the lines should be of consistent diameter throughout their length and as straight as possible to reduce erosion. The valves on the overboard lines should be full opening valves with the same ID as the line and with the same pressure rating as the system. The diverter control system should provide a sequence of events to ensure that the well is never shut-in. The system is generally interlocked so that the selected overboard valve opens and the flowline valve closes prior to the diverter packing functioning. figure 5.g shows a typical diverter hook-up.

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Figure 5.G - Typical Diverter System

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5.4.

RUNNING THE BOP AND RISER SYSTEM

5.4.1.

BOP Stack And Riser Preparation

0

After 20" casing has been run and cemented, the BOP stack and the riser will be run and latched. The BOP stack must be checked and tested and the riser elements inspected in order to have the equipment ready to run as soon as possible after cementing the 20" casing. The following is a list of suggested inspections and tests. 1) 2) 3) 4) 5) 6) 7) 8)

9) 10)

Open all rams. Check the sealing elements for wear or damage. Clean the bore and the ram cavities with a high pressure stream of water in order to be able to detect the presence of dents. Replace the bonnet seals. Visually inspect the annulars sealing elements. Check for trash behind the rubber element of the spherical by measuring the ID of the element. Pressure test the stack on the test stump to its rated working pressure (or to the working pressure of the wellhead connector if this is less than that of the BOP). Function test the BOP through both pods. Each time a function is operated note the volume of the fluid used for the functioning and closing times. These figures are essential to determine whether or not the BOP and its control system are working correctly. Pressure test the choke manifold. Clean and inspect all connectors on the riser sections and pup joints to be used.

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Running The Bop And Riser

Before running the BOP stack check the weather forecast and refer to the ‘Rig Operations’ manual for the maximum vessel motion (heave, roll and pitch) for running BOP. Running procedures vary from rig to rig due to the specific design of the stack and to the handling system (gantry cranes, fork lifts, trolleys, etc.) used for moving the BOP in and out of the moonpool area. There are also a variety of ways to land the BOP stack. For this reason provision of detailed procedures is not possible therefore the following steps are only generic. 1) 2) 3)

Skid the BOP in the moonpool to a position directly under rotary table. Insert the guide lines into the posts of the stack. Place the marine riser handling spider on the rotary table.

4) 5)

Pick up a joint of marine riser using the marine riser handling sub. Lower the marine riser joint through the handling spider and make up to the top of the ball/flex joint. Lift the BOP stack and install a new ring gasket on bottom the of wellhead connector. Make sure the bulls-eye angle indicators are installed above and below the ball/flex joint. Ensure they are visible to the subsea TV system. Lower the BOP stack through the splash zone and land the riser on the handling spider. The first riser joint above the BOP should be long enough to allow the stack to be run into the water to dampen its motions. Continue to run the marine riser on riser joints. The riser couplings should be made up in accordance with the particular manufacturer's recommended procedures. The correct make up and preload of each coupling should be verified prior to its use as a tensile member. Test the choke and kill lines every third joint. Install the required riser pup joints to obtain the correct space out, such that the telescopic joint will be at mid stroke. Pick up the telescopic joint (also called slip joint), locked in the closed position, and install onto the riser assembly. Lower the riser assembly until the outer barrel is at the spider. Land the outer barrel on the spider level. Stroke out the slip joint inner barrel. Remove the handling spider and lower the telescopic joint through the rotary table until the riser t ensioning cables can be installed on the riser tensioning ring. On some rigs the slip joint is run in the collapsed position by using an extra joint of riser temporarily installed above the telescopic joint.

6) 7) 8)

9)

10) 11) 12)

13)

Either the shoe on the inner barrel and/or the pins that lock the slip joint in closed position, should be designed to support the combined submerged weight of the stack and riser as well as dynamic loads.

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Landing The BOP Stack

1) 2)

Tension the guide lines for landing the BOP stack. Run the TV camera or ROV. Focus on the lower extremities of the BOP stack.

3) 4)

Open the motion compensator. Lower the BOP stack until the connector lands on the wellhead housing. Observe the landing with the TV. Latch the connector. With the Motion Compensator make a pick up test of 50,000lbs (15t) above the stack weight to verify the connector is correctly locked down. Adjust the riser tensioners to full working tension as per the rig operating manual and/or riser analysis programme. During the life of the well, it may be necessary to vary the riser tension due to an increase in mud weight or weather conditions. Reduce the tension in the guide wires. Install the choke and kill hoses to the terminal fittings on the slip joint. Install the slip joint packing control lines. By pumping down choke or kill line, test the wellhead connector and the casing against the blind/shear rams to the pressure indicated in the drilling programme. Install the diverter package and rotary table.

5) 6)

7) 8) 9) 10) 11) 5.4.4.

63 OF 234

Testing The BOP Stack

1)

2) 3) 4)

5)

3

Retrieve the 18 /4” nominal seat protector. Do not land the test plug on the seat protector since test pressure will force the protector down, swedging it into the housing. Run the BOP test plug. Fill the running string to the top with water. The string must remain open to atmosphere during the entire test. Pressure test the BOP stack as per Eni-Agip Division and Affiliates Well Control Policy using either one of the two pods. A BOP function test must then be performed on the other pod. Recover the BOP test plug.

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6.

DRILLING MUD

6.1.

GENERAL

For detailed drilling fluid information, refer t o the ‘Drilling Fluids Manual’.

6.2.

a)

A detailed mud programme shall be included as an integral part of the drilling programme.

b)

A Mud Service Contractor may be contracted for the preparation of the mud programme, which shall be submitted to the Company Drilling Office for approval before inclusion in the Drilling Programme.

c)

The same Contractor may be contracted for Mud Engineering on rig site under the control of the Company Drilling and Completion Supervisor.

d)

No variation from the mud programme is permitted without previous discussion with and approval of the Company Shore Base Drilling office.

e)

The mud characteristics to be used for specific operations, such as tripping, casing running, etc., shall be based on specifications described in the relevant sections of the Drilling Programme.

MUD PROPERTIES

1)

2) 3)

4)

The following parameters of the mud shall be regularly checked, recorded; and also reported to Company Drilling Office on a daily basis: Weight 1kg/l = 8.345PPG Temperature (especially in oil mud)

(°C)

Funnel viscosity

(sec)/gal/4

Plastic viscosity

(centipoise)

Yield point

(g/100cm = 0,5lb/100 ft )

Gel strengths

(g/100cm = 0,5lb/100 ft )

Water losses

(cm /30min)

Filter cake

(mm)

Sand content

(% by volume)

Solids content

(% by volume)

Oil content Calcium content

(% by volume) (mg/l Ca ++)

Salinity

(g/l Cl-)

2

2

2

2

3

The Company Drilling And Completion Supervisor shall be notified immediately of any change in mud properties. The Driller shall be notified immediately of any variation in mud weight, chloride content, gas or any other property which may indicate significant changes in the formation drilled and/or entry into overpressurised zones. Mud weight and funnel viscosity shall be recorded at least every 30mins at the flow line and suction pit.

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5)

7)

Mud weight Salinity Maximum gas Pit level Interested volume Depth and time.

The Mud Engineer shall check mud weight at the shakers and downstream of the degasser continuously when circulating gas cut mud and/or bottoms up. Rheology shall be checked three times a day or more frequently if requested by Company Drilling and Completion Supervisor.

8)

Solids control shall be performed using the appropriate equipment, whenever needed. Maintain the right pressure on the desander and desilter manifold for maximum performance.

9)

Any addition of oil to the water base mud system shall be previously approved by Company Drilling Office. If offshore, the standby boat should be topped up with barite at all times. Never transport barite in tanks that previously held cement, except in an emergency. Meter the water and brine additions to the drilling fluid. Report usage daily. Slug the drill pipe with mud from the standby reserve. If returns are lost, immediately fill the annulus with water. Measure the volume of water required and continue filling the hole until the hole stands full. Do not pull the drill pipe out of the hole until the hole stands full. A thorough inventory of mud stock will be made on a weekly basis.

10) 11) 12) 13)

14) 6.3.

0

When circulating gas cut mud and/or bottoms up, the following data shall be recorded:

• • • • • • 6)

65 OF 234

SAFETY ACTIONS

1) 2)

3)

4) 5) 6) 7)

The active mud pit level shall be manually measured and recorded at least every 30 minutes. An automatic pit level device shall be installed and operational, at all times, on all mud pits and on the trip tank. A pit volume recorder shall be continuously working on the rig floor and on the Mud Logging Unit. Any change in mud volume shall be immediately notified to the Driller and to the Mud Logging Engineer. The Driller shall be constantly aware of the causes of any pit level fluctuation. Gas detectors shall be operational at all times. The degasser shall be used whenever gas presence in the mud is indicated by the gas detector. Special care shall be given to the suction and discharge of the degasser to assure maximum equipment reliability. The Drilling Contractor may be requested to assign a person to monitor and control the shale shaker area during all times t hat hole conditions demand.

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1) 2)

6.4.

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If H2S is present safety precautions will be adopted as specified in (STAP-P-1-M-6035 E). A ventilation room that provides at least one complete air change cycle every two minutes will be installed in the mud pit room.

DRILLING WITH OIL-BASED MUD

The following issues should be considered when drilling with oil base muds: a)

To avoid pollution, precautions shall be in place (drains from the rig floor and shale shakers, cuttings treatment, etc.) in order to avoid environmental spillage.

b)

The safety of the crew shall always be paramount to prevent oil mud/skin contact and accidents such as tripping, f alling, hand crushing, etc.

c)

Maintain the cleanliness of the rig.

d)

Oil resistant equipment (various pack-off, seals on mud pits, etc.) must be used.

e)

Control of air quality in the pits and shale shakers room is a main concern when oil base mud is used and the capacity of the ventilation system should be at least one complete air change every minute.

f)

For fire control, the ventilation system shall keep the air/gas mixture below the combustible limit, however in case of fire, the system shall be automatically shut down as the blowers would feed the fire with fresh air

g)

Well control is affected by the use of oil based mud as it can create hazards while handling drilling gas and gas kicks. Since a gas influx may dissolve completely into the drilling fluid, small influxes of gas are more difficult to detect. Gas expansion and pit gain do not occur as the influx is circulated toward the surface. Detection may be delayed until the influx is only a few hundred feet from the surface when the well suddenly starts to flow. Usually there is little time for the rig crew to react to divert the flow. If this occurs, large volumes of mud and gas may be unloaded onto the rig floor and up into the derrick.

h)

Since there is no equipment or equipment arrangement to take care of the undetected gas influx as described in g) above, the problem of gas influx has to be overcome by careful planning.

i)

The Drilling Contractor and the Company shall prepare and agree on a set of specific rules and procedures.

j)

The basic guidelines when drilling with oil based muds are the following:

• • •

When drilling or coring known gas formations, be aware of potential for gas break out and sudden unloading. When back on bottom after tripping with gas formations exposed to the open hole, be alert to sudden unloading of the hole as bottoms up near surface. A suspected but not detected influx shall be circulated to a predetermined distance below the BOP stack (e.g., 500ft), the annular or upper pipe rams will then be closed and bottoms up circulated out through the choke, under control to the mud/gas separator.

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MINIMUM STOCK REQUIREMENTS

a)

Minimum stock requirements for mud weighting materials, chemicals, pipe freeing agent, dispersant, lost circulation material, cement, kill and reserve mud on the rig, depends on the well pressure prognosis, severity of potential drilling problems and rig load capacity.

b)

The minimum barite stock shall be 100t. When overpressurised formations are anticipated, barite stock shall be based on expected formation pressure gradients, on the actual mud weight and on the volume of the active drilling fluid in the system.

c)

The minimum cement stock shall be 100t. or at least enough to prepare 200m of cement plug.

d)

A minimum volume of 70m of kill mud at 1.4kg/l shall be stocked while drilling surface hole without a BOP stack installed.

e)

After nippling up a BOP stack, minimum requirements for kill mud cannot be specified. The volume and density of kill mud shall be adjusted to the well pressure prognosis and pit volumes available on the rig.

f)

Properties of reserve and kill mud should be checked and maintained daily and recorded the mud report.

g)

In addition, the following material is recommended to be available onsite for contingencies:

3

• • • • • •

A stock of diesel oil, enough to guarantee five day of operations. Pipe freeing agent. The quantity shall be sufficient to prepare two pills, the volume of each one shall be two times the capacity of the annulus open hole/BHA. 20 drums of dispersant. Mica (fine, medium and coarse)-1.5t of each. 3t of Wall Nut. Viscosifier for salt water (i.e. Biopolymer): the quantity shall be sufficient to prepare 200m 3.

The inventory of materials on the rig should be reviewed daily and replenishment arranged immediately when stock levels approach the specified minimum requirement. With regard to barite, cement and diesel oil, should the stocks fall below the minimum requirement, drilling operations shall be suspended.

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7.

TRIPPING AND FILL-UP PROCEDURES

7.1.

GENERAL PROCEDURES

1) 2)

The Company Drilling and Completion Supervisor shall be present on the rig floor at the beginning of every trip to check for f ill-up. Before the start of tripping out of the hole with drill pipe, the following criteria must be followed, unless authorised by Company Drilling and Completion Manager/Drilling Superintendent:

• • • • 3)

A flow check shall be taken at the following points:

• • 4) 5) 6)

Bottoms up must be circulated. No loss of circulation must be recorded. No indication of on influx. The mud density going into and coming out of the hole shall not differ more than 24g/l (0.2ppg).

Immediately above off bottom. At the lowest casing shoe (regardless of the fill-up status).

Prior to the start of tripping out, make sure that mud is conditioned in order to have the minimum gel strength value within the desired values. Before each trip, the rotary slips shall be inspected for worn or broken inserts and any replacements made. Replacement inserts should be available on the rig at all times. Prior to pulling out of hole, the drill pipe should be slugged with a heavy pill. The volume and density of the pill should be determined by Company Drilling and Completion Supervisor based on the following factors:

• • • •

Density of mud in the hole. Mud rheology. Capacity of the drill pipe. Hole depth.

As a general rule, it is preferable to pump a small volume pill of high density than a large volume pill of low density. Under the following circumstances, the use of slug pill should be avoided:

• • •

Shallow hole. Possibility of damaging the reservoir with weighting agent. When an increase in mud weight should be avoided in order to prevent mud losses and/or fracturing the formation.

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The following formula is often used to calculate the pill's volume. Volume

=

Drop x Mud Weight x DP Capacity Mud Weight of Pill − Mud Weight

where: ‘Volume’ is in BBL. ‘Drop’ is in ft and represents the desired draw down in the string. ‘Mud Weight’ is in PPG. ‘DP Capacity’ is in BBL/ft. 7)

8)

9)

10) 11)

12)

13) 14)

15) 16) 17)

18)

The ‘Wiper rubber’ should be used when pulling or running the drill pipe to prevent any objects falling into the hole. Do not install the wiper rubber while tripping out the first 10 stands in order to observe the fluid level. In an area where formations contain (or are suspected to contain) hydrogen sulphide or other toxic gas, air breathing apparatus should be worn to observe the well at the bell nipple. Always use the trip tank (in and out) and accurately record volumes to make sure the hole is taking/giving the proper amount of fluid. If any discrepancy is observed, the Driller shall immediately inform the Tool Pusher and Company Drilling and Completion Supervisor. As a general rule, if the hole fails to take enough mud, run the drill string to bottom and circulate bottoms up. In case of trip tank failure, an alternative will be to use a mud pump. In this case the annulus will be filled with mud every 5 stands of pipe. Volumes will be monitored by isolating the suction tank and closely monitoring fluid volumes. A visual check of the annulus should ensure the mud level is dropping normally while pulling pipe. The trip (or fill-up) sheet shall be filled in on the rig floor while tripping. The Driller shall submit the trip sheet to the Company Drilling and Completion Supervisor at the end of the trip or when requested. If drill pipe is pulled wet, the mud has to be returned to the hole. Drain the ‘Mud Saver Bucket’ into the bell nipple. A suitable safety valve, threaded (or with proper connections) to fit each pipe connection included in the string, must be on the rig floor, in the open position ready for use with proper fittings and handling devices. The closing/opening wrench must be readily available for immediate use. Any time a trip is interrupted, the hand tight installation of a safety valve is recommended. The drill pipe shall be pulled and run in the hole at such rate as to prevent swabbing and pressure surges. If possible, and if required by hole conditions, rotate the string when tripping to prevent sticking while standing back pipe.

Use a pipe spinner or chain under the following circumstances when:

•

Tripping out a core barrel.

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• • • • • • 19) 20)

21)

22)

23) 24) 25)

26)

27)

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Caving problems are encountered. Tripping out from thief zones. Tripping out from kick off zones (deviated holes, side-track, etc.). Pulling out running tools. Pulling string with an expected washout. Pulling a broken string or fish.

The standard break out technique should be adopted in order to have all the tool joints in the drill string broken out and doped alternatively. No welding/strapping shall be allowed on the BHA unless expressly required by the Company Drilling and Completion Supervisor for special reasons taking into consideration the particular tools and their position in the BHA. In case of drag when tripping out, do not exceed a reasonable value of overpull usually 1 /3 of string weight. This value should be adjusted to hole conditions, drill string design and stabilisation and hole profile (vertical, side-track, directional). If necessary, work the pipe (i.e. rotate) and/or install a Kelly and circulate to pass through the tight spot. If drag is encountered when tripping in, install the Kelly and wash/ream the free zone. Never attempt to push the bit through a ledge. No weight should be placed on the bit during reaming. Torque, and sometimes pressure, are the only guide parameters to perform this operation. While reaming pay attention in order to avoid making a new hole. Always record depths and overpulls of troublesome zones on the ‘IADC’ and Company Daily Drilling Reports. Torque all joints to the API recommended value. A short trip shall be performed before tripping out of overpressurised zones, unless advised otherwise by the Company Drilling Manager and/or Superintendent. The following procedure shall be carried out for a short trip: a)

Pull 5 to 10 stands at normal speed, making sure the hole is taking the proper amount of mud (no swabbing). Use the trip tank accurately.

b)

Run back to bottom.

c)

Perform a flow check on the bottom.

d)

Circulate and check bottoms up.

e)

If an influx is detected, increase the mud weight as necessary.

f)

A second short trip may be required.

Gauge accurately the residual diameter of the bit and stabilisers in order to plan a subsequent reaming operation or change the drilling string design if a PDC or diamond bit is scheduled. It is recommended to use a three point gauge ring if available. The blind or shear rams must be closed every time tools are out of the hole.

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TRIPPING WITH A TOP DRIVE

When using a top drive, the following points should be noted:

7.3.

a)

Tripping is still handled in the conventional manner. The link tilt feature can be used to tilt the elevator to the derrick man, enhancing his ability to latch it around the pipe thus improving trip times.

b)

The link tilt has an intermediate stop which is adjustable to set the elevator at a convenient working distance from the monkey board. The intermediate stop is tilted out of the way to allow the elevator to reach the mouse hole.

c)

The elevators may be positioned in any direction by unlocking the rotation lock and rotating the pipe handler.

d)

The elevators will return to their original position if rotated by the drill string.

e)

If a tight spot or key seat is encountered while tripping out the hole, the drilling motor may be spun into the stand at any height in the derrick and circulation and/or rotation established immediately to work the pipe through the tight spot.

FLOW CHECKS

When required, a flow check shall be performed as follows: 1) 2) 3) 4) 5)

6)

During a trip, remove the wiper rubber. Pick up the drill string until the tool joint is in correct position above the rotary table and the BOP can be closed properly on the pipe body. Stop the mud pumps (piston and supercharged type). Line up to the trip tank. Observe the trip tank indicator and visually check for flow observing the mud level in the annulus. The duration of the test shall be at least 15 minutes or whatever time is necessary to determine without any doubt that the well is static or flowing. Nevertheless, keep the time the drill string is not circulating as short as possible. If flow is observed, close the BOP and begin well control procedures. Otherwise, resume drilling operations.

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8.

DRILLING STRING DESIGN/STABILISATION

8.1.

STRAIGHT HOLE DRILLING

It has been confirmed through observation that a drilling bit will attempt to up move toward o an up dip in laminar formations with dips angles up to 40 . A factor in consideration of this is the bending characteristics of the drill string. With no weight on the bit, the only force acting on the bit is the result of the gravitational weight of the portion of the string between the bit and the tangency point. The force caused by this weight tends to bring the hole back towards vertical. When weight is applied, there is a bending of the string and subsequently a force on the bit which tends to direct the hole away from the vertical. The results of these two forces will either cause an increase in angle, decrease in angle, or to remain at a constant angle. This theory is based on the assumption that the drill string will lie on the low side of an inclined hole. 8.2.

DOG-LEG AND KEY SEAT PROBLEMS

8.2.1.

Drill Pipe Fatigue

If a programme is designed in such a way that drill pipe damage is avoided, while drilling the hole, then the hole will be acceptable for conventional casing, tubing and production string designs, as far as dog-leg severity is concerned. A classic example of the severe dog-leg condition which produces fatigue failures in drill pipe can be seen in figure 8.a. The stress at point B is greater than the stress at point A; but as the pipe is rotated, point A moves from the inside of the bend to the outside and back again, so that every fibre of the pipe undergoes both minimum tension and maximum tension every rotation. Cyclic stress reversals of this nature cause fatigue failures in drill pipe, usually within the first 2ft (0.6 m) of the body adjacent to the tool joint due to the abrupt change of angle. To avoid rapid fatigue failure of pipe, the rate of change of the hole angle must be controlled. Suggested limits are given in figure 8.b. This graph is a plot of the tension in the pipe versus 1 change in hole angle in degrees per 100ft. This curve is designed for a 4 /2" 16.60lb/ft Grade ‘E’ drill pipe and represents the stress endurance limits of the drill pipe under various tensile loads and in various rates of change in hole angle. If conditions fall to the left of this curve, fatigue damage is avoided, but to the right, fatigue damage will build up rapidly and failure of the pipe is likely. It can be seen from this plot that with a dog-leg high in the hole with high tension in the pipe, only a small change in angle can be tolerated. Conversely, if the dog-leg is close to total depth, tension in the pipe will be low and a larger change in angle can be t olerated. Note:

Refer to figure 8.c for the maximum safe dog-leg limits when using Grade ‘E’ drill pipe. If the stress endurance limit of the drill pipe is exceeded, an expensive fishing job or a junked hole could occur.

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Stuck Pipe

Sticking can occur by sloughing or heaving of the hole or also by extra large OD drill collars into a key seat while tripping the drill string out of the hole. 8.2.3.

Logging

Logging tools and wire line can become stuck in key seats. The wall of the hole can also be damaged, causing future hole problems. 8.2.4.

Running casing

Running casing through a dog-leg can cause serious problems. If the casing becomes stuck in the dog-leg, it will not extend through the productive zone. This would make it necessary to drill out the shoe and set a smaller size casing through the productive interval. Even if running the casing to bottom through the dog-leg is successful, the casing could be severely damaged, thereby preventing the running of production equipment inside the casing. 8.2.5.

Cementing

Dog-legs will force casing tightly against the wall of the hole, preventing a good cement bond as no cement can circulate between the wall of the hole and the casing at this point. 8.2.6.

Casing Wear While Drilling

The lateral force of the drill pipe rotating against the casing in the dog-leg or dragging through it while tripping, can cause substantial wear to the casing. This could cause drilling problems and/or a possible serious blow-out. 8.2.7.

Production Problems

In rod pump completions rod wear and tubing leaks, associated with dog-legs, can cause expensive remedial costs. It may be difficult to run packers and tools in and out of the well without getting stuck because of distorted or collapsed casing. It is obviously preferred to produce through straight tubing to avoid friction losses and prevent turbulence.

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Figure 8.A - Dog Leg and Key Seating

Figure 8.B - Endurance Limit For 16.60# Grade E Drill Pipe

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Figure 8.C - Maximum Safe Dog leg Limits 8.3.

HOLE ANGLE CONTROL

In order to reduce the possible causes of bit deviation and the problems associated with crooked holes, There are two possible solutions, one using the pendulum and the other the packed BHA concepts. 8.3.1.

Packed Hole Theory

A packed hole assembly is used to overcome crooked hole problems and the pendulum is used only as a corrective measure to reduce angle when the maximum permissible deviation has been reached. The packed hole assembly is sometimes referred to as the ‘gun barrel’ approach because a series of stabilisers is used in the hole already drilled to guide the bit straight ahead. The object is to select a bottom hole assembly to be run above the bit with the necessary stiffness and wall contact tools to force the bit to drill in the general direction of the hole already drilled. If the proper selection of drill collars and bottom hole tools is made, only gradual changes in hole angle can develop. This should create a useful hole with a fullgauge and smooth bore free from dog-leg, key seats, offsets, spirals and ledges, thereby making it possible to complete the well.

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Pendulum Theory

The forces which act upon the bit can be resolved into:

8.4.

a)

The axial load supplied by the weight of the drill collars.

b)

The lateral force, the weight of the drill collar between the bit bit and the first point of contact with the wall of the hole by the drill collar i.e. Pendulum force. This force is the tendency of the unsupported length of drill collar to swing over against the low side of the hole due to gravity. It is the only force that tends to bring the hole back towards vertical.

c)

The reaction of the formation to these loads may be resolved into two forces, one parallel to the axis of the hole and one perpendicular to the axis of the hole.

DESIGNING DESIGNI NG A PACKED HOLE ASSEMBLY

The following factors need to be considered when designing a packed hole assembly. 8.4.1.

Length Of Tool Assembly Assembly

It is important that wall contact assemblies provide sufficient length of contact to assure alignment with the hole already drilled. Experience confirms that a single stabiliser just above the bit generally acts as fulcrum or pivot point and will build angle because the lateral force of the unstabilised collars above will cause the bit to push to one side as weight is applied. Another stabilising point, for example, at 30ft (10m) above the bit will nullify some of the fulcrum effect. With these two points, this assembly will stabilise the bit and remove some of the hole angle-building tendency, but it would still not be considered a good packed hole assembly. As shown in figure 8.d, two points will contact and follow a curved line, but the addition of one more point makes it impossible to follow a curve. Therefore, three or more stabilising points are needed to form a packed hole assembly. 8.4.2.

Stiffness

Stiffness is probably the most misunderstood of all the issues to be considered about drill collars and the realisation of the importance of diameter and that it is proportional to stiffness, e.g. if a bar diameter is doubled its stiff ness is increased sixteen fold. table 8.a shows moments of inertia (I), which is proportional to stiffness, for the most popular drill collars in various diameters. Large diameter drill collars are the ultimate in stiffness, so it is important to select the maximum diameter collars that can be saf ely run.

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Three or more stabilising points make a packed bottom hole assembly.

3

2

2

2

1

1

1

Figure 8.D - Packed Hole Assembly Stabilising Points 4

OD (ins)

ID (ins)

I (ins )

5"

2 /4"

29

6 /4"

1

2 /4"

6 /2"

1

2 /4"

6 /4"

3

2 /4"

7"

2 /16"

8"

2 /16"

9"

1

74

1

86

1

100

13

115

13

198

2 /16"

13

318

10"

3"

486

11"

3"

713

Table 8.A - Drill Collar Stiffness

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Clearance

The closer a stabiliser is to the bit, the more exacting the clearance requirements are. If, for 1 example, a /16" under-gauge from hole diameter is satisfactory just above the bit, then 60ft 1 above the bit, /8" clearance can be critical factor for a packed hole assembly. 8.4.4.

Wall Support and Length of Contact Tool

Bottom assembly must adequately contact the wall of the hole to stabilise the bit and centralise the drill collars. The length of contact needed between the tool and the wall of the hole will be determined by the formation. The surface area in contact must be sufficient to prevent the stabilising tool from digging into the wall of the hole. If this should happen, stabilisation would be lost and the hole would drift. If the formation is strong, hard and uniform, a short narrow contact surface is adequate and will insure proper stabilisation. On the other hand, if the formation is soft and unconsolidated, a long blade stabiliser may be required. Hole enlargement in formations that erode quickly tends to reduce affective alignment of the bottom hole assembly. This problem can be reduced by controlling the annular velocity and mud properties. 8.5.

PACKED BOTTOM HOLE ASSEMBLIES

Proper design of a packed bottom hole assembly requires a knowledge of crooked hole tendencies and the degree of drillability of t he formations to be drilled in each particular area. For basic design practices the following are considered pertinent parameters and are defined as: a)

Crooked Hole Drilling Tendencies

• • • b)

Mild crooked hole Medium crooked hole Severe crooked hole.

Formation Firmness

• • • •

Hard to medium hard formations Abrasive Non abrasive Medium hard to soft formations.

figure 8.e shows three basic assemblies required to provide the necessary stiffness and stabilisation for a packed hole assembly. A short drill collar is used between zone 1 and zone 2 to reduce the amount of deflection that might be caused by the drill collar weight. As a general rule of thumb, the short drill collar length in feet is approximately equal to the hole size in inches, plus or minus two feet. For example a short drill collar length of 6 to 10ft (23m) would be satisfactory in an 8“ hole.

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* The short drill collar length is determined by the hole size Hole size (inches) = Short DC (ft) +/- 2ft

Figure 8.E - Basic Packed BHAs

0

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8.6.

80 OF 234

0

PENDULUM BOTTOM HOLE ASSEMBLIES

Because all packed assemblies will bend to some extent, however small the amount of deflection, it is not possible to make a perfectly vertical hole. The rate of hole angle change may be kept to a minimum for normal deviation but occasionally conditions will arise where the total hole deviation must be restricted to closer tolerances. When this condition occurs the pendulum technique is employed, however if it is anticipated that a packed hole assembly will be required after reduction of the hole angle, the packed pendulum technique is recommended. The pendulum assembly is based on the principle that the only force available to straighten a deviated hole is the weight of the drill collars between the point of tangency (stabiliser) and the bit. In the packed pendulum technique, a pendulum length of collars are slung below the regular packed hole assembly in combination. When hole deviation has been dropped to an acceptable limit, the pendulum collars are removed and the packed hole assembly is again run above the bit. It is then only necessary to ream the length of the hole equal to the length of the pendulum collars prior to resuming normal drilling. If a vibration dampening device is used in the packed pendulum assembly, it should remain in its original pick-up position during the pendulum operations. (Refer to figure 8.f ).

Figure 8.F - Pendulum BHA

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8.7.

81 OF 234

0

REDUCED BIT WEIGHT

By reducing the weight on the bit, the bending tendency of the drill string are changed and the hole will be straighter. One of the earliest techniques for straightening the hole was to reduce the weight on the bit and speed up the rotary table. In recent years it has been found that this is not always the best procedure because reducing the bit weight sacrifices considerable penetration rate. Worse than this, it frequently causes dog-legs as illustrated in 8.7. Therefore as a point of caution, the straightening of a hole by reducing bit weight should be done very gradually so that the hole will tend to return to vertical without sharp bends and be much safer for future drilling. A reduction of bit weight is usually required when changing from a packed hole assembly to a pendulum or packed pendulum drilling operation.

Figure 8.G - Reduced Bit Weight

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8.8.

82 OF 234

0

DRILL STRING DESIGN

The normal drill string design practice aim is to avoid abrupt changes in component cross sectional areas. Abrupt changes can lead to concentrations in bending stresses which in turn can lead to a twist off (Refer to figure 8.h). The ratio I/C between the moment of inertia (I) and radius (C) of the pipe is directly related to the resistance to bending (Refer to Section 8.4.2). The following are used to determine the section modulus I/C: I

= Moment of inertia 4

4

= π/64 x (OD - ID ) C

= Radius of the tube = OD/2

At a crossover from one tubular size to another size, the ratio (I/C large pipe)/(I/C small pipe) should be less than 5.5 for soft formations and less than 3.5 for hard f ormations. table 8.b shows the ratio (I/C) for the most common sizes of drill pipes, HW drill pipes and drill collars. table 8.c illustrates some possible drill strings and their acceptable use.

Figure 8.H - Bending Moment

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OD (ins) 1 3 /2 1 4 /8 3 4 /4 3 5 /4 3 5 /4 6 6 1 6 /4 1 6 /4 1 6 /2 1 6 /2 3 6 /4 3 6 /4 7 1 7 /4 3 7 /4 3 7 /4 8 8 1 8 /4 1 8 /4 1 8 /2 9 1 9 /2 10 1 11 /4 12

83 OF 234

REVISION

Drill Collar ID (ins) 1 1 /2 2 1 2 /4 1 2 /4 3 21 /16 1 2 /4 3 2 /16 1 2 /4 3 2 /16 1 2 /4 3 2 /16 1 2 /4 3 2 /16 3 2 /16 3 2 /16 3 2 /16 3 3 2 /16 3 3 2 /16 3 3 3 3 3 3 3

STAP-P-1-M-6140

0

OD (ins) 3 2 /8 3 2 /8 7 2 /8 7 2 /8 1 3 /2 1 3 /2 1 3 /2 4 4 1 4 /2 1 4 /2 1 4 /2 5 5 5 1 5 /2 1 5 /2 1 5 /2 5 6 /8

Drill Pipe ID (ins) WT 2 4.85 1.815 6.65 2.441 6.85 2.151 10.40 3 9.50 2.764 13.30 2.602 15.50 3.476 11.85 3.340 14.00 3.958 13.75 3.826 16.60 3.640 20.00 4.408 16.25 4.276 19.50 4.000 25.60 4.892 19.20 4.778 21.90 4.670 24.70 5.965 25.20

I/C 4.1 6.6 9.8 18.3 17.6 20.8 20.2 23.3 22.7 26.7 26.2 30.1 29.6 32.7 37.5 44.6 44.4 49.5 49.3 55.9 54.2 59.2 71.0 83.8 97.2 138.8 154.5

I/C 0.7 0.9 1.1 1.6 2.0 2.6 2.9 2.7 3.2 3.6 4.3 5.1 4.9 5.7 7.3 6.1 7.1 7.8 9.8

Extra Weight Pipe OD (ins) 1 4 /2 5

ID (ins) 13 2 /16 3 1

l

=(Moment of Inertia)

C

= Radius of the Tube in inches

Ratio =

4

WT 32.0 42.6 4

= ( /64) x (OD - ID ) x 3.142

I / CDrillCollars I / CDrillPipes Table 8.B - I/C Ratios for standard Tubulars

I/C 7.7 10.7

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IDENTIFICATION CODE



Hole Size (ins)

Drill Collar/Drill Pipe (ins)

I/C Ratio

83.8

1.5

DC 8 /4 x 21 /16

55.9

9.8

DP 5 x 19.5lbs/ft

5.7

-

Not

DC 9 /2 x 3

83.8

1.5

Recommended

1

55.9

7.1

DP 5 /2 x 19,5lbs/ft

7.8

1.4

DP 5x 19.5lbs/ft

5.7

-

83.8

1.5

OK for

DC 8 /4” x 2 /16

55.9

5.2

SOFT

HWDP 5” x 42.6lbs/ft

10.7

1.9

Formations

DP 5” x 19.5lbs/ft

5.7

-

83.8

1.5

”

55.9

2.5

OK For HARD

DC 6 /4 x 2 /16”

13

22.7

1.9

Formations


5.7

-

1 1

3

1

13

DC 8 /4 x 2 /16 1

1

0

I/C

DC 9 /2 x 3

17 /2

84 OF 234

1

DC 9 /2 x 3 1

13

1

DC 9 /2 x 3 1

13

DC8 /4 2 /16 1

Remarks

Note: For every hard formations, add HWDP 1

1

12 /4”

DC9 /2” x 3”

83.8

1.5

1

13

55.9

2.5

OK For HARD

DC 6 /4 x 2 /16

1

13

22.7

3.9

Formations


5.7

-

DC 8 /4 x 2 /16”

Note: For every hard formations, add HWDP 1

1

12 /4”

DC9 /2” x 3”

83.8

1.5

DC 8 /4 x 2 /16”

1

55.9

5.2

OK For SOFT


10.7

1.9

Formations

DP 5” x 19.5 lbs/ft

5.7

-

1

1

8 /2

13

13

DC 6 /4 x 2 /16”

22.7


5.7

1

13

DC 6 /4 x 2 /16”

22.7


10.7


5.7

Not

3.9

Table 8.C - Drill String Acceptability

Recommended Recommended

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8.9.

85 OF 234

0

BOTTOM HOLE ASSEMBLY BUCKLING

Without weight on the bit, a drill string is straight if the hole is straight. With a sufficient small weight applied on the bit, the string will remain straight. As the weight is increased, a critical value of weight is reached and the drill string will buckle and contact the wall of the hole. If the weight on the bit is further increased, a new critical value is reached at which the drill string buckles a second time. This is designated as ‘buckling of the second order’. With still higher weights on the bit, buckling of the third and higher orders occur. When a buckled string is rotated, stresses in the outside fibres of the tubulars develop. These stresses increase in accordance with the diameter of the hole and results in fatigue failure of the string. As soon as a drill string buckles in a straight hole, the bit is no longer vertical and a perfectly vertical hole cannot be maintained. Therefore, in the design of BHAs, it is important to determine the critical values of weight on bit at which buckling occurs. The critical weight on bit of the first order (W cr1) and second order (W cr2) are given by the following equations: W cr1 = 1.94 x m x p W cr2 = 3.75 x m x p Where: m

=

Length of one dimensionless unit, in metres

p

=

Weight in mud per unit of length of the pipe, in kg/m

The dimensionless unit ‘m’ is a function of Young's modulus for steel, moment of inertia of the pipe cross section and weight in mud per unit of length of the pipe. The values of ‘m’ for various sizes of drill collar are plotted in f igure 8.i. Under normal conditions, some buckling of the drill string is inevitable, therefore stiffer collars and stabiliser should be used for control of the hole angle.

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0

m 28

11" * 3" 9 1/2" * 3" 8 1/4" * 3"

26

8 1/4" * 2 13/16" 8" * 3" 8" * 2 13/16"

24

7 1/2" * 2 13/16"

22

20

18 1,0

1,2

1,4

1,6

1,8

2,0

2,2

Mud Weight (kg/l)

m 21

6 3/4" * 2 13/16" 6 3/4" * 2 1/4"

20

6 1/2" * 2 13/16" 6 1/2" * 2 1/4"

19

6" * 2 13/16" 6" * 2 1/4"

18

4 3/4" * 2 1/4"

17

16

15

14 1,0

1,2

1,4

1,6

1,8

2,0

2,2

Mud Weight (kg/l)

Figure 8.I - Dimensionless Unit (m) for Various Sizes of DC

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8.10.

87 OF 234

0

SUMMARY RECOMMENDATIONS FOR STABILISATION

a)

For the vertical section of the hole the purpose of stabilisation, more than any other factor, is to maintain the drift angle as close as possible to zero and, if applicable, to prevent wall sticking.

b)

For deviated holes, the stabiliser positions in the BHA depend entirely on directional drilling requirements and as a rule determined by the Directional Engineer.

c)

All stabilisers shall be the ‘integral type’ and machined from a single block of material or the ‘integral sleeve type’ fitted by head or hydraulic pressure (not threaded).

d)

The spiral profile of blades, for both string and near bit type stabiliser, shall be the ‘right hand type’.

e)

All stabilisers for hole size up to 12 /4” must be the tight type in order to assure a 1 complete (360°) contact with the borehole. All stabilisers for hole size over 12 /4" must be open type but not less than 210°.

f)

The maximum allowed diameter in consideration to the grooves shall be diameter of the fishing neck.

g)

All stabilisers should have a fishing neck with the same OD as the drill collars and a length not shorter than 20” for stabilisers up to 6” hole size and 26” for larger hole size stabilisers.

h)

All stabilisers smaller than 15" OD shall have three blades. Stabilisers larger than 15" shall have four blades as standard.

i)

Stabilisers (and subs, etc.) should be demagnetised after a magnetic particle inspection.

j)

The maximum allowable reduction value on outside diameter of stabilisers should be according to the attached tables .

k)

Tungsten carbide smooth surface solid body integral blade stabilisers are preferred. 1 Integral sleeve stabilisers may also be used in large hole sizes above 12 /4", mainly as the near bit stabiliser, in order to position the stabilisation point right on top of the bit.

l)

The maximum allowable wear of the stabiliser blades should be in accordance with the previous point. If such a limit is reached at any point, the stabiliser has to be replaced.

1

≥ the outside

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IDENTIFICATION CODE



Hole Size

Body OD

5 /4

3

4 /32

5 /8

7

4 /32

6 8 /8

3 1

8 /2

Rotary Conns

Blade OD String Type

21

NC 38

5 /32

21

NC 38

5 /32

4 /32

21

NC 38

5 /32

6 /8

3

NC 46

8 /16

6 /8

3

NC 46

5 /32

23

5 /32

23

5 /32

3

8 /64

8 /16

5

5

12

5

12

12 /64

5

15 /4

3

15 /4

5

15 /4

3

15 /4

5

17 /4

3

17 /4

5

17 /16

3

17 /4

5

22 /16

11

22 /4

5

22 /16

11

22 /4

5

25 /16

11

25 /4

5

25 /16

11

25 /4

5

27 /16

11

27 /4

7 /8

7

6 /8 R

12 /4

1

9 /8

3

7 /8 R

16

9 /8

3

7 /8 R

16

10 /8

8 /8 R

3

7 /8 R

7

1

9 /8

17 /2

1

10 /8

8 /8 R

23

9 /8

3

7 /8 R

23

10 /8

8 /8 R

26

9 /8

3

7 /8 R

26

10 /8

28

10 /8

17 /2

7

7

Blade OD Near Bit Type

19

1

12 /4

88 OF 234

7

8 /8 R

7

8 /8 R

0

Length of Length of Fishing Pin End Neck

Length of Min Width Box Bit of Blades

19

20

12

10

2

23

20

12

10

2

27

20

12

10

2

13

26

12

10

2 /2

8 /64

21

26

12

10

2 /2

12 /64

3

26

12

10

3

3

26

12

10

3

3

26

12

10

4

3

26

12

10

4

1

26

12

10

4

1

26

12

10

4

3

26

12

10

4

3

26

12

10

4

3

26

12

10

4

3

26

12

10

4

3

26

12

10

4

Main dimensions of string and near bit type stabilisers are in ins. Table 8.D - Acceptable Dimensions For Used String And Near Bit Stabilisers

The maximum overall length, for string type stabilisers only, must be as follows:

• • •

3

75" for 5 /4" to 6" hole size stabilisers 3 1 85" for 8 /8" to 12 /4" hole size stabilisers 100" for 16" to 28" hole size stabilisers.

1 1

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IDENTIFICATION CODE



Hole Size

Body OD

89 OF 234

Rotary Conn.

Blade OD String Type

0

Length of Fishing Neck

Length Pin End

Minimum Width of Blades

27

20

12

2

6

4 /32

21

NC 38

5 /32

1

6 /8

3

NC 46

8 /16

5

26

12

2 /2

5

12

26

12

3

5

12

26

12

3

5

15 /4

3

26

12

4

5

17 /16

3

26

12

4

8 /2 1

7 /8

7

6 /8 R

12 /4

1

9 /8

3

7 /8 R

16

9 /8

3

7 /8 R

1

9 /8

3

7 /8 R

12 /4

17 /2

1

Main dimensions of string and near bit type stabilisers are in ins. Table 8.E - Acceptable Dimensions For Used String And Near Bit Stabilisers

The maximum overall length must be as follows:

• • • 8.11.

75" for 6" hole size stabilisers 1 1 85" for 8 /2" to 12 /4" hole size stabilisers 1 100" for 16" to 17 /2" hole size stabilisers.

OPERATING LIMITS OF DRILL PIPE

The design of the drill string for static tensile loads requires sufficient strength in drill pipe to support the submerged weight of drill pipe and drill collar below. The submerged load (P) hanging below any section of drill pipe can be calculated as follow: P= L dp x Wdp

+(L c xWc ) xK b

where: Ldp Lc

=

Length of drill pipe in feet

=

Length of drill collar in feet

W dp

=

Weight per foot of drill pipe in air

Wc

=

Weight per foot of drill collar in air

Kb

=

Buoyancy factor

The difference between the maximum allowable tension and the calculated load represents the Margin of Over Pull (MOP): MOP = (Pt x 0.9) - P where: Pt 0.9

=

Theoretical tension load from table

=

Design factor

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0

The minimum recommended value of MOP is 60,000lbs (27t) and it shall be calculated for the topmost joint of each size, weight, grade and classification of drill pipe. The anticipated total depth with next string run and expected mud weight should be considered when calculating the MOP. The overall drilling conditions (directional well, hole drag, likelihood of becoming stuck, etc.) may require higher values of MOP. When the depth is reached where the MOP approaches the minimum recommended value, stronger drill pipe shall be added to the string. 8.12.

GENERAL GUIDELINES

Packed hole assemblies shall generally be used unless otherwise dictated by hole conditions. Standard packed hole assembly should be:

• • •

•

Bit + Near Bit Stab + Short DC (7ft =2.5m) + String Stab + K Monel DC + String Stab + 2 DC + String Stab. A stabilised string can be used to drill out shoe-tracks after casing setting unless there is so much cement left inside the casing to discourage such a procedure. If the bottom hole assembly is different from the one previously used, run in the hole with maximum care, monitoring the weight indicator closely. Any indication of string dragging must be promptly detected. Tight zones must be reamed free before proceeding with the trip. Any change in the stabilisation from that specified in the drilling programme must be authorised by the Company Drilling Office

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9.

DIRECTIONAL DRILLING Controlled Directional Drilling can be defined as the technique of intentionally deviating a well bore so that, the bottom hole location or any intermediate portion of the hole, is positioned in a predetermined target(s) area, that is located at a given horizontal and vertical distance from the surface location of the well (refer to the ‘Directional Drilling Manual’). Many new tools and techniques have been developed in recent years to enhance the accuracy of this technique.

9.1.

TERMINOLOGY AND CONVENTIONS True North:

The direction from any point on the earth's surface to the geographic north pole which is fixed.

Magnetic North:

The direction from any point on the earth's surface to the magnetic north pole.

Magnetic Declination:

The angle between True North and the direction shown by the north pointer of a compass needle at the location being considered, measured from True North. Magnetic declination for a given location changes gradually with time, An annual rate of change is applied to give the present declination. The magnetic declination and rates of change are obtained from detailed charts or computer program. To obtain the geographic direction, the direction obtained from magnetic surveys shall be corrected simply by adding or subtracting the appropriate declination.

Direction:

Directions can be measured and given in three ways:

•

Azimuth, where the angle is measured from north in a clockwise direction from 0 to 360° (for example: 252° AZ). Quadrant Format (called ‘Field Co-ordinate’ or ‘Oil Field • Format’), the direction is expressed as an angle E or W of N or S (the 252 AZ becomes S72°W). Bearing Angle, the angle is measured from 0 to 180° • East (positive) or West (negative) of North (108° W or 108°). The correction due to magnetic declination is the same for any of the three formats. Inclination (Inc) also termed Drift:

The angle the centre line of the well bore makes with a vertical axis below the well. By definition, straight holes have zero angle of inclination. All inclination angles are positive.

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0

Target:

A predetermined area of interest whose position is defined by its horizontal and vertical distance from the surface location of the well.

Well Path:

The path of the bore hole drilled by the bit.

Projected Well Path:

The path expected of the bit to follow beyond the end of the well bore.

Station:

A survey data point. A station length is the measured footage between stations. The well path is that provided by all of the data points therefore a well path survey is all the data points surveyed.

Survey Data

The inclination angle, the direction of the well bore is pointing and the measured depth of the surveying instrument.

Build Up Rate (BUR):

The build-up rate should be kept as close as possible to the designated well trajectory ensuring that the build-up neither lags behind nor exceeds the projected well path. Large rates of build-up result in increased torque and wear on drill pipe and casing, and in the problems associated with accidentally side tracking or formation of key seats. Insufficient build-up rate will result in an increased final angle required to achieve o the objective; generally build-up rates of 1.5 to 3.0 /100ft are normally used.

Dog Leg Severity (DLS):

The rate of change of the combination of both inclination and direction of a well path between data points. It is usually expressed in degrees per 100ft or 30m interval drilled.

Tangent Section:

The section of the well starting from the end of build up and where direction and inclination are maintained constant.

Horizontal Displacement (or Horizontal Departure):

The distance projected onto a horizontal plane from the origin to the point under consideration.

Vertical Section:

The projection of the horizontal displacement onto a vertical plane usually along the target direction.

Lead Angle:

When drilling with rotary drilling assemblies there is a tendency for the hole to ‘walk to the right’. Turbine drilling assemblies have the opposite tendency, that is ‘walk to the left’. The lead is the angle to be applied to the project direction at kick-off to correct the walking tendency of the drilling assemblies.

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9.2.

CO-ORDINATE SYSTEMS

9.2.1.

Universal Transverse Of Mercator (UTM)

0

In the Transverse Mercator Projection the surface of the spheroid chosen to represent the Earth is wrapped in a cylinder which touches the spheroid along a chosen meridian. From the centre of the globe (Refer to figure 9.a), shapes on the surface of the spheroid are transferred to the surface of the cylinder (A becomes A1 and B becomes B1). The cylinder is then unwrapped giving a correct scale representation along the central meridian and an increased scale away from it.

NORTH POLE (AXIS)

CIRCLE OF CONTACT A1

A

B1

B

Figure 9.A - Universal Transfer Of Mercator

As a Mercator projection becomes increasingly inaccurate as one moves away from the chosen meridian, a series of reference meridians is used so that it is always possible to use a map with the reference meridian close to the place of work. The reference meridians used are 6 degrees apart providing 60 maps, called zones, to cover the whole world. The zones are numbered 0 to 60 (from west to east) with zone 31 having o o the 0 meridian (Greenwich) on the left and 6 E on the right. o

Each zone is further sub-divided into grid sectors each one covering 8 latitude starting from the equator. Grid sectors are identified by the zone number and by a letter ranging from C to X (excluding I and O) from 80° South to 80° North. Identification of the sector is simply the number and letter of the relevant area, i.e. 31U being the Southern North Sea (Refer to figure 9.c). The co-ordinates for each UTM grid sector are given in metres with the origins (i.e. the zero value) at a line 500,000m West of the centre meridian to avoid negative values and at the equator. The co-ordinates are given as Eastings and Northings.

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0

Example

UTM co-ordinates of the rig: 410,261.0 E 6,833,184.2 N The rig is 500,000 - 410,261m west of the central meridian and 6,833,184.2m north of the equator. The bearing between any two points in the same grid sector is referenced to Grid North which is the direction of a straight line running from top to bottom of the map. Convergence is the angle ‘a’ (Refer to figure 9.b) between the Geographic North and the Grid North for the location being considered measured from Geographic North. In the northern hemisphere the convergence is positive for locations east of central meridian and negative for locations west of central meridian. The opposite applies for the southern hemisphere.

G

G

G

N G True North

G

NORTH (CENTRAL MERIDIAN)

G

-

+

a EAST EQUATOR LINE

WEST

+ CENTRAL MERIDIAN

SOUTH

Figure 9.B - Convergence Angle

9.2.2.

Geographical Co-ordinates

Generally rig and target co-ordinates are given in either UTM and/or geographical coordinates. Geographical co-ordinates are expressed in degrees, minutes and seconds for Latitude and Longitude. Each degree is subdivided into 60 minutes and each minute further subdivided into 60 seconds (Refer to figure 9.c). Example

Rig location: 3° 36'

01.0" E Longitude

40° 43'

06.5" N Latitude

For the purpose of calculations degrees, minutes and seconds are often converted into decimal degrees. This is done by dividing the minutes by 60 and the seconds by 3,600 so that 3° 36' 01" becomes: 3 + 36/60 + 1/3600 = 3,600.278°

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IDENTIFICATION CODE


95 OF 234


° 8 0 N

0

N 8 0 °

60

0 5

10

15

20

25

30

35

40

45

50

55

° 8 0 S

S 8 0 °

THE METHOD OF ZONE NUMBERING ACCORDING TO THE UTM SYSTEM ESCH ZONE IS 6° LONGITUDE IN WIDTH AND EXTENDS FROM 80° NORTH TO 80° SOUTH 27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

64 V

56 U

31 U

48 T

40 S

32 R

24 Q

16 P

8 N

0

DEGREE

-8 -24 -18 -12 -6

0

6

12 18 24 30 36 42 48 54 60 66 72

Figure 9.C - Grid Sectors

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9.3.

96 OF 234

0

RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT

The first step in planning a well, starts with the data defining the rig and target locations, generally in UTM or geographical co-ordinates. With these data the horizontal displacement and direction to the target can be calculated. If the data supplied for the rig and target location are in geographical co-ordinates these must first be converted to UTM data. 9.3.1.

Horizontal Displacement

Using UTM co-ordinates (Refer to Figure), displacement and direction can be determined with trigonometry as shown in the following example. UTM co-ordinates of rig:

410,261.0 E 6,833,184.2 N

UTM co-ordinates of target:

412,165.0 E 6,834,846.0 N

Absolute difference in Eastings:

1,904.0m

Absolute difference in Northings:

1,661.8m

1904,0 m

TARGET

48,9° 1661,8 m

H D 2527,21 m

RIG Figure 9.D - Example Calculation Of Horizontal Displacement

The origin used may correspond to wellhead or slot in a template. The horizontal displacement (HD) to the target is thus: HD = (1661.82 + 1904.02)½ = 2527.21m

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Target Direction

The bearing to the target is:

φ 9.3.3.

1

= tan (1,904.0 : 1,661.8) = 48.90° or N 48.90° E

Convergence

The target co-ordinates and bearing, as calculated above , are relative to the Grid North. Since survey data make reference to the Geographic North (also called True North), the convergence must be applied to the target co-ordinates and bearing to present them relative to the Geographic North. Taking convergence as being 1.45° in this example (Refer to figure 9.e), it is necessary to rotate the target location about the origin of the well by -1.45° to place it in its relative position to True North.

True North

GRID NORTH NEW TARGET

Target Grid North

-1,45° Grid Convergence

RIG

Est EST

Fig. (a)

Fig. (b)

Figure 9.E - Example Grid Convergence

In the previous example the bearing of the target with respect to Grid North was 48,90° or N 48.90° E. Then the target bearing relative to the T rue North is: 48.90 - 1.45 = 47.45° or N 47.45° E The horizontal displacement remains the same but its co-ordinates change. The True North co-ordinates of the target are calculated with trigonometry as follow: Eastings = 2,527.21 sin 47.45 = 1,861.76 Northings = 2,527.21 cos 47.45 = 1,708.98

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HIGH SIDE OF THE HOLE AND TOOL FACE

The high side is the top of the hole viewed along the bore hole axis. Assuming the hole has an inclination, the low side is the path, that a small, heavy ball would follow if it is rolled slowly down the well (Refer to figure 9.f).

a

HIGH SIDE

HIGH SIDE

ROLLING BALL

LEFT

RIGHT

a ROLLING BALL

LOW SIDE

LOW SIDE

VERTICAL

Figure 9.F - Definitions of Inclined Hole

During a kick off or correction run, the measurement of greatest value is tool facing, since it indicates the orientation of the bent sub. When a MWD or steering tool is used to control the deviation, tool face is referred to the high side of the hole when sufficient inclination exists o o (over 5 ) or to magnetic North for low inclinations (up to 5 ). The gravity tool face angle (GTF) is the projection onto a plane perpendicular to the hole axis of the angle between high side of the hole and tool face. The magnetic tool face angle (MTF) is the projection onto horizontal plane of the angle between magnetic North and tool face(Refer to figure 9.g)

MAGNETIC NORTH

HIGH SIDE

45° TOOL FACE

TOOLFACE

LEFT

RIGHT

LOW SIDE

Steering the mudmotor by means of magnetic toolface bit and mud motor, trying to kick off in the direction of 45° magnetic azimuth

Steering the mudmotor by means of gravity toolface bit and mud motor, trying to build angle and turn well to the right

Figure 9.G - Magnetic Tool Face

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Magnetic Surveys Length Of Non Magnetic Drill Collar

Magnetic instruments must be run inside a sufficient length of non-magnetic drill collars (NMDC or Monel Collar) made of special nickel alloy to allow the instrument to respond to the earth's magnetic field, by isolating it from the magnetic influence of the drill string. The required length of NMDC is determined by taking into account the following factors:

• • •

The geographical area of operations. Since the earth's horizontal magnetic intensity varies geographically, a zone selection map is used to determine which set of empirical data should be used for a given area. The proportion of steel drilling tools below the NMDC. The direction and inclination of the well.

The Directional Drilling Contractor shall provide updated indication of magnetic intensity related to the area of operation. Compass spacing is generally recommended to be at or below the centre of the nonmagnetic collars. Magnetic Single Shot Surveys

Prior to use, the instrument should be thoroughly checked out and tested to ensure it is in good working condition. After loading, the timer is set and synchronised with a watch on the surface. o

The speed of the falling instrument is approximately 1,000ft per min for inclinations up to 40 o and 800 ft per minute for inclinations over 40 . A safety margin of 5 mins shall be added to the calculated running time. Mud weight and viscosity are important factors to be considered, as are drill string restricted internal diameters. o

For high inclinations (over 60 ) sinker bars should be used and the survey barrel may need to be pumped down. The mud pump rate should be very low, giving just sufficient pressure to break circulation. The drill string may be rotated slowly (not however, if running the survey on wireline) and reciprocated to prevent sticking and assist the survey tool in reaching bottom. Drill pipe movement and pumping (if used) should be continued until a minute or so before the timer is due to operate.. If run on wireline, it should be taken into account the time the instrument generally takes longer to assemble and to run. Sandlines are quicker to run but can cause higher wear on drill pipe protective linings. Whichever wireline is used, thread protectors should be installed on the tool joint.

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Magnetic Multishot Surveys

Magnetic multishot surveys are generally run prior to running casing as a check on the single shot surveys taken while drilling. This survey may be run either as an inrun or running outrun survey, although it is generally run on the outrun wiper trip before casing. This gives an opportunity for the instrument to be retrieved at the casing shoe and checked whilst the trip back to bottom is being made. A second opportunity is then available if necessary. As the name implies, the magnetic multishot provides a series of single shot surveys. The camera of the instrument, instead of carrying one single shot disc, contains a length of photographic film. The film is exposed and advanced continuously, at a set time interval, from the time the instrument is started until stopped. The interval between exposure is generally 20sec but it is altered on some instruments. The survey is normally made by dropping the instrument into the drill string and allowing it to get to bottom before pumping the slug and commencing the trip out of the hole. As the drill string becomes stationary in the slips after each stand is broken off, the time since starting the instrument is recorded together with the number of stands out of hole. This enables the survey picture to be correlated to instrument depth. With an instrument set on a twenty second sample rate, good practice is to ensure there are a minimum of two surveys taken at each depth by remaining stationary. Steering Tool (with mud motor)

Steering tools use a system of magnetometers and accelerometers to measure the Earth's magnetic field and gravity in order to determine inclination and direction. The tool is run on a conductor wireline which provides power for the sensors and returns the signal to the surface computer where it is decoded and relayed to the rig floor read out. The tool may be operated on one of two modes displaying tool face with respect to North (Magnetic Tool Face) or relative to the high side of the hole (Gravity Tool Face). The magnetic tool face mode is used in vertical or near vertical wells for kick off in the desired o direction. As the inclination is increased above about 5 , the tool is switched to gravity tool face. The advantages of steering tools over single shot orientation are in the continual read-out of the tool face whilst drilling and in saving time in situations where orientation problems may require repeated single shot surveys. One of the drawbacks of the system is the time required to pull the tool out of hole for making pipe connections. The steering tool system is used only in specific situations, i.e. KOP in a high temperature zone. When a motor is used for kick off or correction runs (operations not requiring rotation of the drill string), a side entry sub may be used. This sub prevents the need to pull the tool to make connections. The wireline passes through the entry sub enabling the drill pipe to be added to the string in the normal manner.

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Measurement While Drilling (MWD)

Measurement While Drilling is a technique which takes various downhole measurements and transmitting these data to the surface for decoding and display. The most common transmission media is mud pulse telemetry in which the flowing column of drilling mud is modulated periodically by some mechanical means within the downhole assembly. The intermittent pressure pulses are transmitted from downhole to the surface where they are detected by a pressure transducer mounted in the standpipe. The transducer converts the mud pulses into electrical signal that is then transmitted to the surface computer. The computer decodes and displays this transmitted information. There are three distinct types of MWD transmission systems currently available, all using mud column as their transmission medium:

• • •

The positive system uses a plunger type valve that momentarily obstructs mud flow thus creating a positive, transient pressure pulse. The negative pulse system utilises a valve that momentarily vents a portion of the mud flow to the borehole annulus, resulting in a negative, transient pressure pulse. The continuous wave system utilises a spinning, slotted rotor and slotted stator that repeatedly obstructs mud flow. This operation generates a continuous low frequency fluctuation in standpipe pressure of approximately 50psi.

One of the most common applications for a directional MWD system is to orient downhole motor/bent sub assemblies when changing the course of the well path. Sensors located immediately above the bent sub, taking measurements while the bit is drilling on bottom, provide immediate data (inclination, azimuth and tool face) to the Directional Driller. As already discussed in the description of steering tool systems, tool f ace may be referred to magnetic North or high side of the hole, depending on hole inclination. 9.4.2.

Gyroscopic Surveys

Gyro instruments are used when the proximity of casings or other magnetic interference precludes the use of magnetic tools.

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Gyro Single Shot Surveys

Gyro single shot surveys are carried out on wireline. Since gyroscopes are delicate instruments, running speeds should be within that recommended and the tool stopped and started off gently. The gyro instrument has the same mule shoe feature as the magnetic single shot used for orientation and, although it uses a different system, the data obtained is the same, (i.e. hole direction, inclination and tool face). The maximum depth to which they can be ef fectively run is approx. 1,300ft about 400m. This is a limitation imposed by the time taken between orienting the gyro on surface, running into hole, taking the survey, pulling out of hole and checking the orientation. The difference in azimuth between the initial orientation and final check on return to surface is the amount the gyro has drifted or wandered off its true north orientation. The drift is assumed to be constant for the time interval between initial and final orientation. The correction is calculated by simply determining the proportion of drift occurring in the time o from the initial orientation to the survey picture being taken. Gyro drift is approx. 4 per hour o in static conditions and 8 per hour in dynamic conditions. Gyro Multishot Surveys

The gyroscopic multishot is the survey tool for surveying extended intervals inside casing or drill pipe without a non-magnetic drill collar. The tool comes in two sizes. The smaller one can be run in completed wells or through drill pipe. The larger one is a more rugged tool and is used to run surveys inside casing. Depending on the length of survey run, it will be a number of hours before the calculated survey data are available. Gyro multishot drifts are the same as t hat of the single shot gyro. Surface Read-out Gyroscopes

Surface read-out gyroscopes are used for the same purposes in single shot and multishot data collection. The instrumentation is more sophisticated and requires a conducting wireline to power the tool and transmit the information back to the surface for decoding by computer. With a surface read-out multishot gyro, the drift can be constantly monitored to ensure the tool is performing well and the calculated survey is produced shortly after completing the log run. Gyrocompass (North Seeking Gyroscope)

These instruments use the principle of earth rate gyro compassing to define true azimuth and inclination in near vertical parts of the borehole. Then, as the hole builds angle to above o 15 , it switches to a continuous integrating mode. This dual mode makes the tool accurate in either vertical and deviated borehole where it eliminates the inaccuracies that gyrocompass based instruments have at high latitude, high inclination or in the East/West axis. The rugged construction makes these tools capable of steering and surveying while drilling (Gyro While Drilling).

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Survey Calculation Methods

When drilling on a cluster, the co-ordinates of the centre of the 30" conductor shall be used on the rig for computations of each individual well. The centre of the cluster may be used by the Company Drilling Office for mapping, planning and reporting. There are a number of methods of calculating the wellbore trajectory from the survey data. The most common are:

•

•

•

Average angle method: It assumes the borehole is parallel to the simple average of both the drift and bearing angles between two survey stations. It is fairly accurate and calculation is simple enough for field use with a non programmable scientific calculator. (Refer to figure 9.h). Radius of curvature: Using sets of angles measured at the upper and lower ends of sections along the surveyed course length, it generates a space curve representing the wellbore path. For each survey interval, it assumes that the vertical and horizontal projections of the curve have constant curvature. Minimum curvature method: Shall be used on the rig, in Company Drilling office and Directional Drilling Contractor office for survey computations. It assumes the borehole is a spherical arc with minimum curvature (maximum radius of curvature) between survey stations. It is the most accurate for most boreholes, however it requires very complex calculations using a programmable calculator or computer.

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Average Angle Method

∆ North = ∆MD x sin(l1 + L2 ) / 2 x cos A1 + A2

/2

∆ East = ∆MD x sin(l1 + l 2 )2 x sin( A1 + A 2 ) / 2 ∆ Vertical = ∆MD x cos(l1 + l 2 )/ 2

A1

A2 I1

N W

I2 E

S

Radius Of Curvature Method

∆ North = ∆ East =

∆MD x (cos l1 − cos l2 ) x (sin A2 − sin A1) (l2 − l1) x ( A 2 − A1)

A1

∆MD x (cos l1 − cos l1) x (cos A1 − cos A 2 ) (l2 − l1) x ( A 2 − A 2 ) I1 A2

I2

N E

W S

Minimum Curvature Method ∆ North = (∆MD)/ 2 x

+ sin l2

x cos A 2 x RF

∆ East = (∆MD ) / 2 x (sin l1 x sin A1 + sin l2

x sin A 2 ) x RF

sin l1 x cos A1

DL 2 A1

∆Vertical = (∆MD)/ 2 x (cos l1 + cos l2 ) x RF RF

= 2 / DL x tan (DL / 2)

cos(DL ) = cos(l − l) − sin l x sin x [1 − cos ( A

DL 2

I1 DL

− a )]

N

A2 I2

E

W S

Figure 9.H - Survey Calculation Methods

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Drilling Directional Wells Kicking Off The Well

Jetting is the term used to describe the deviation of a well using bit hydraulics to erode the formation in a particular direction. A special jetting bit may be used or a conventional tricone bit run with two undersized and one oversized (or blanked) jet nozzles. Usually the bit is run on a typical build up assembly (bit, full gauge near bit stabiliser, orienting sub, non-magnetic and steel-drill collars as required) and once on bottom the blind nozzle, representing the ‘tool face’, is oriented in the desired direction. Maximum circulation is then established and the washing action begun. Some of string weight is slackened on the bit and the weight indicator will give an indication of drilling off if the formation is soft enough to be washed out. In formations where the degree of compactation makes jetting ineffective, deviation is started with a downhole motor. This has become the most commonly adopted method of kick off. With downhole motors, bent and orienting subs (or combined bent/orienting sub) are required. With the deflection assembly in the hole, there is a correction to apply to the desired tool face setting or proposal direction. This correction is due to the reactive torque developed by downhole motors. Reactive torque is dependent on motor power, weight on bit, formation, hole inclination and drilling assembly design and length. The actual value of reactive torque must be assessed as drilling proceeds as it is unique to the conditions prevailing. During the kick off, the advantages and/or disadvantages of the different methods of orientation are highlighted. With single shot orientation, reactive torque can only be estimated based on the experience of the Directional Driller in the area of operation. Since the survey tool is at least one joint above the bit, the first assessment of actual reactive torque can be made only after the second joint has been drilled. Steering tools provide the most accurate measurement of tool face position. A continuous read-out on surface enables adjustment of the weight on bit/rate of penetration in order to maintain a constant tool face. MWD tools provide the same information with the advantage of not requiring wireline and the consequent rigging up and trip time. On the other hand, steering tools provide extremely high data rates that may be of critical importance when drilling with very high rates of penetration. Build Up Section

After the desired direction has been reached, the kick off assembly may be replaced with a rotary build up assembly. However, if jetting has been the method of initial control, drilling can continue with the same BHA in the rotary mode without requiring a trip. Selection of the appropriate build up assembly is dependent upon the angle achieved during initial kick off and maximum angle required. figure 9.i illustrates the response of some bottom hole assemblies. The decision of when and if to replace the kick off assembly depends on several factors such as hole size, weight on bit and rate of penetration, response of the kick off assembly, residual bit life and final planned inclination. Controlling the BUR is imperative if fatigue to drill pipe and drill collars is to be avoided.

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This can be accomplished by varying the drilling parameters (weight on bit, rotary speed and pump pressure) or changing the BHA. In this case careful assessment must be made to consider whether the amount of time lost in tripping out of hole to change the assembly, would be gained later with a better rate of penetration or by preventing diff iculties. The alternative is to accept the current performance and make adjustments at the next bit trip. Tangent Section (Hold On Section)

When the desired inclination has been reached, the kick off or build up assembly is replaced with a stiff bottom hole assembly that will maintain the inclination and direction. Small variation in behaviour of a BHA can be obtained by adjusting the weight on bit and rotary speed. figure 9.k, illustrates some common holding assemblies. Providing it is necessary, the earlier a correction to inclination or direction can be made the better it is. As the bit get closer to the target, longer corrections are required to get the well back on the target. Advanced planning should be continuously done during operations to ensure that, should a trip become necessary at short notice, any change to the BHA may be made at the same time. Drop Off Section

Drilling a directional well it may be necessary to allow the drift angle to straighten back to vertical or near vertical. figure 9.l shows some common drop off assemblies. Drop off assemblies should be used starting with the least successful. The reason being that the higher the inclination, the greater the pendulum effect and the same rate of drop might o be achieved with the least successful assembly at 50 and the most successful assembly at o 30 . Therefore, as the inclination is reduced, stronger dropping tendency assemblies may be run to maintain the rate of drop required. Only where the maximum negative side force is required, at low inclinations and in hard formations, should pendulum assemblies be run (i.e. assemblies without a near bit). Care Of Stabilisers

The bottom 120ft (40m) of a drilling assembly is the critical portion for controlling a 1 directional well. The stabilisers used in this area should be full gauge to /16" under unless under-gauge stabilisers are required to hold or drop angle. Stabilisers shall be gauged each trip: undersized tools should be moved up higher in drill collar assembly or replaced with full gauge tools (Refer to Section 8.10). All stabilisers shall be magnafluxed at the end of each well phase. As a general rule, do not drill out the casing shoe with a ‘packed hole assembly’. However, the decision whether or not to use stabilisers to drill casing shoe shall be evaluated case by case.

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String Stabiliser Drill Collars 60' Drill Collars

Maximum Angle Building Assemblies

30' Drill Collars

Near Bit Stabiliser

Near Bit Stabiliser

Bit

Bit

String Stabiliser

String Stabiliser

30' Drill Collar 30' Non Mag. Drill Collar 30' Non Mag. Drill Collar Near Bit Stabiliser

Near Bit Stabiliser

Bit

Bit

Maximum Angle Building Assemblies

String St abilisers String Stabiliser 30' Non Mag. Drill Collar

String Stabilizer 30' Non Mag. Drill Collar

30' Non Mag. Drill Collar

String Stabilisers

String Stabilisers

10' Drill Collar

10' Drill Collar

Near Bit Stabilisers

Near Bit Stabilisers

Bit

Bit

String Stabiliser

10' Drill Collar

Near Bit Stabilier Bit

Figure 9.I - Build up Assembles

Packed Hole Assemblies

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0

Bottom Hole Assembl Res onse Assembly

Response

No.

Relative * response stenght

Bit

Near bit stabiliser (Approx. 3-5' from bit face to leading edge of stabiliser) 90'

1

Build

10

2

Build

8

3

Build

7

60'

30'

60'

30'

4

Build

7-3

5

Build

7-5

6

Build

5-3

7

Build

4-2

30'

45'

15'

30'

30'

30'

15'

30'

30'

15'

30'

30'

15'

30'

5-10'

30'

45'

8

Build (drops under certain circumstances)

3-2 30'

9

Hold

1

10

Hold

10

11

Hold

9

12

Hold

8

13

Hold

5-8

14

Hold

1-3

15a

Drop

10

15b

Drop

10

16

Drop

5 - 10 **

17

Drop & Build

30'

30'

30'

30'

60 - 70'

60 - 70'

30'

45'

18 19

108 OF 234

30'

Drop (at highter incl.) and/or Build (at lower incl.) Drop or Build (highly dependent on collar OD)

* 10 is the highest and 1 is the lowest

30'

= Undergauge

** (smaller holes con be better than 15)

Figure 9.J - Bottom Hole Assembly Response

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NEAR BIT STABILISER 3' - 6'

ASSEMBLY A

30'

15' 20'

30' - 60' or 90'

MOST SUCCESFUL

3' - 6'

ASSEMBLY B

5' 15'

30'

30' - 60' or 90'

30'

MODERATELY SUCCESFUL

3' - 6'

30' - 34'

30' or 60'

30' or 60'

ASSEMBLY C

30' - 60' or 90'

LEAST SUCCESFUL

Figure 9.K - Common Holding Assembly

ASSEMBLY A

3' - 6'

15' 20'

30'

30' - 60' or 90'

MODERATELY SUCCESFUL 3' - 6'

ASSEMBLY B

5' 15'

30'

30' - 60' or 90'

30'

LEAST SUCCESFUL

3' - 6'

30' - 34'

30' or 60'

ASSEMBLY C MOST SUCCESFUL

Figure 9.L - Drop Off Assembly

30' or 60'

30' - 60' or 90'

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Dog Leg Severity

Changes in hole curvature are often referred to as dog-legs The severity of a dog-leg is determined by the average changes in angle and/or direction calculated on the distance over which this change occurs. For example, if there is a 3° change in angle (no direction change) over 100ft of hole, the dog-leg severity is 3° per 100ft. Until a dog-leg reaches some threshold value, no drill stem fatigue damage occurs. This threshold value is called the Critical Dog-leg. The critical dog-leg is dependent upon the dimension (size) and metallurgy of the drill pipe and drill pipe tension (pull) in the dog-leg. The planning of directional wells should include a ‘Dog-leg control programme’. Critical dog leg limits should also be considered for drill collars. Dog-leg limits are established to prevent drill pipe fatigue, but when those limits are maintained, there is also a reduction in associated hole problems. Excessive dog-legs cause key seats, casing wear, rotating torque, trip drag, etc. Overall drilling rate can be greatly improved by a carefully planned and executed dog-leg control programme (Refer to Section 8.1). 1)

If extreme torque is encountered during drilling deviated holes, consider the following (in order of priority):

• • • 2) 3) 4) 5)

Improve hole cleaning verifying the flow velocity in the drill pipe/open hole annulus and adjusting mud properties (high instantaneous gels, low viscosity and, conditions permitting, high mud weight). Add a non-polluting torque reducer additive or, if possible, diesel oil (to a maximum of 10% diesel) to the mud. On the subsequent trip leave out some drill collars and stabilisers. Replace with HWDP. Replace the near bit stabiliser with a near bit roller reamer (if available).

Set casing through the build up section to 200-300ft (60-90m) in the tangent section, if possible. The use of hard-banded drill pipe is not allowed inside casing. Check the DP tool joints every trip with a fixed caliper. It is recommended to have a magnet placed in the flow line to collect metal cuttings coming out of the hole. Excessive metal cuttings may indicate casing wear or collision with another well (on a cluster). In case of indications that the drill pipe and casing are eroding , the f ollowing actions are suggested:

• • • • • •

Check alignment of derrick over the centre of t he well. Check the wear bushing on the first trip. Use lowest practical rpm and consider the use of downhole motor. Use the minimum practical weight of bottom hole assembly. Do not rotate with the bit off bottom. Install protectors at less than 3ft (1m) above worn tool joints and, if so required, also 3ft (1m) below tool joints in any section of the top hole where the hole curvature makes it necessary. Minimum OD of the protectors is 7”.

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1)

2) 3) 4) 5)

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Inspect the DP after a certain amount of thousand feet is drilled, or rotating hours, specified by the Company Drilling Office. This operation shall be carried out by a recognised inspection company. Drill collars, stabilisers, subs, etc. shall be checked at the end of each well. Read the single shot survey film discs or MWD data to ensure the correct path is being followed. Check survey calculations for correctness. Keep well plot updated every time a new survey is taken. The baffle plate for the survey instrument should be located at the bottom of the bottom non-magnetic drill collar.

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10.

CORING

10.1.

CORE BARREL TYPES AND USES

To achieve the optimum core recovery with regard to quantity and quality under widely varying conditions, a variety of coring equipment has been designed to meet this as follows: 10.1.1. Wireline

The Wireline, or Drill Core system, can be used for continuous drilling and/or coring operations. The inner barrel or the drill plug centre of the core bit can be installed by dropping it from the surface and retrieving it by wireline thus avoiding pulling of the drill string. 10.1.2. Marine Core Barrels

The Marine Core Barrel was developed for offshore coring, where a stronger core barrel is required. The marine core barrel is very similar to the conventional core barrel except that the outer tube has heavier wall thickness. 10.1.3. Rubber Sleeve

The Rubber Sleeve Core Barrel is a tool designed for a special application to recover undisturbed cores in soft, unconsolidated formations. As the core is cut, it is encased in the rubber sleeve, which contains and supports it. Using face discharge ports in the bit, the contamination of the core by circulating fluid is reduced. The rubber sleeve core barrel has proven to be a very effective tool, even although it has limitations; i.e.:

• •

Only one size of barrel is available which is limited to cutting a 20ft core. The rubber sleeve becomes weak with a tendency to split if the temperature increases to above 80° C.

10.1.4. Conventional Core Barrel

Because of the Conventional Core Barrel's reliability, ease of operation and simplicity of maintenance, it is unsurpassed for trouble f ree operation. Listed in table 10.a are the various sizes of core barrels for conventional and special coring systems. In table 10.b, are listed the core system applications and in table 10.c are the comparison of coring operations. The reason for the wide range of core barrel sizes is the variance in hole sizes drilled throughout the world, and the availability of fishing t ools. Generally in most instances, it is better to cut and recover the largest diameter of core possible, while still having the ability to wash over and fish for the core barrel. The larger the core, the less the formation that has to be cut by the core bit, and the faster will be the penetration rate. When coring broken or fractured type formations, the larger core tends to hold the natural position and cause less jamming problems.

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Core Barrel Type

Series 250P

Aluminium Inner Tube

Marine Series Slim Hole Fibreglass Inner Tube

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Outer Tube OD Core Size (ins) (ins) CONVENTIONAL CORING SYSTEMS 1 1 4 /8 2 /8

Inner Tube Length (ft)

30 - 120

4 /4

3

2 /8

5

30 - 120

5 /4 1 6 /4

3

3 /2 4

1

30 - 120 30 - 120

6 /4

3

4

30 - 120

8 3 4 /4

5 /4 5 2 /8

1

30 - 120 30 - 90

5 /4

3

3 /2

1

30 - 90

6 /4 8

3

4 1 5 /2

30 - 90 30 - 90

4 /2

1

2 /8

1

30 - 120

6 /4

1

3

30 - 120

1

1 /4

3

30

3 /2

SPECIAL CORING SYSTEMS 3 5 4 /4 2 /8

30 - 90 30 - 90

6 /4

3

4

8

5 /4

1

30 - 90

4 /4

3

2 /4

1

30

5 /4 1 6 /4

3

3 1 3 /2

30 30

6 /4 8

3

3 /2 3 4 /4

1

30 30

6 /4

3

4

30

3

6 /4 3 6 /8

1

3 /2 3

30 20

Pressure Core Barrel

6

2 /2

1

10 - 20

Wireline Drill-Core

1

6 /4

2

13 - 26

1

3 4

15 - 30 45

PVC Inner Tube

Full Closure System Rubber Sleeve

Marine Soil Sampler HD45 Long Distance Barrel

6 /4 3 6 /4

Table 10.A - Various Core Barrel Sizes

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10.1.5. Inner Tubes

A variety of inner tubes are available to match the formation and application:

• • •

Standard steel inner tube Fibreglass inner tube Aluminium inner tube.

Fibreglass and aluminium tube are designed to recover undisturbed cores to the surface and to allow them to be transported from the field to the laboratory without damage or contamination. The fibreglass inner tube bears temperatures up to 150°C. Aluminium tubes are used to recover cores from extreme temperature wells or other environments where fibreglass tubes are not suitable. Fibreglass and aluminium inner tubes are machined in the same manner as the standard steel tubes and can be interchanged without modification. Therefore coring is performed in exactly the same manner as coring with conventional steel inner tubes. 10.1.6. Modified Barrels Liners

In the past few years the conventional and marine core barrels have been modified by adding inner barrel liners. Plastic liners (PVC or ABS) provide an economical protection for cores of soft, friable, broken or otherwise unconsolidated formations and help to protect and preserve the core during removal and transportation. Plastic liners are run inside conventional steel inner barrels and, hence, recover a smaller OD core. They must be used with a special adapter and core heads. Oriented Coring

Oriented coring provides important geological information such as the direction of faults and fractures, the amount and direction of dip, etc. Most of the conventional barrel types can also be adapted for oriented coring. A special shoe assembly with knives is installed for lightly scribing grooves in the core as it enters the inner barrel and an electronic multishot, set in a non magnetic collar above the barrel, is aligned with one of the knives. The pressure relief plug is replaced by a rod extending up into the non-magnetic collar, providing support for the survey instrument. The directional survey instrument has a reference mark on the shoe, by a connecting rod through the inner barrel. Once the position of the directional survey instrument and the mark on the shoe is locked, the core can always be orientated towards north.

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Recoverable Formation Properties

Standard Full Closure System

Consolidated Formations



0

Rubber Sleeve

ContainPressure erised Core Core







Soft, Unconsolidated Formations







Formations Prone to Jamming







Formations Prone to Washing



In-situ Formation Properties, i.e. oil water saturation, mobile oil, gas content, etc.



Table 10.B - Core System Applications

Type

Relative Cost High

Low

Conventional PVC Ployglass x Rubber-Sleeve x Wireline x Pressure Barrel x Sponge Barrel x Sidewall (1) = In oil base mud. (2) = CO2 only.

x

Ease of Operation

Quality of Samples

High

High

Low

x

x x x x

x x

x

x x

Por

Low

x x x x x

x x

Perm

x

Oil x x x x x x x x

x x x x x x x x

Table 10.C - Comparison of Coring Operations

x x

Saturation H2O Gas

x x(1)

x x(2)

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GENERAL GUIDELINES

1)

1

3

Coring in 8 /2" holes shall be carried out by using a conventional core barrel (6 /4” x 4”) 1 1 1 or Marine Core Barrel (6 /4" x 3" or 7 /4" x 4") with a 8 /2" diamond or PDC core head. 1 3 Coring in 12 /4" holes can be carried out by using a standard core barrel (6 /4” x 4”, 1 1 1 1 6 /4” x 3”, 7 /4” x 4”), Marine Core Barrel (6 /4" x 3" or 7 /4" x 4") or a full size core barrel 1 1 (8" x 5 /4 ") with a 12 /4 " core head. The full size core barrel is preferable when long section of hole must be cored 3

5

Coring in a 6” hole can be carried out using t he conventional core barrel (4 /4” x 2 /8”) 2)

Core barrels can be run in multiples of 30ft sections to a maximum of 180ft. Continuous coring can be carried out using a tool length according to the field practice and the type of core barrel in use.

3)

The inner tube material(steel, aluminium, fibreglass, etc.) or liner (PVC, ABS, etc.) shall be chosen according to the formation characteristics and bottom hole temperature. Ensure that the necessary fishing equipment is available before running the core barrel. Check the inner tube's integrity and space-out prior to running in the hole. The core barrel shall be stabilised on bottom and top with special stabilisers in order to reduce the wear on the gauge of the bit with, consequently, crooked and under gauged holes. 1 15 15 If a 8 /2" core bit is used, the stabiliser will have a 8 /32" OD. If a 8 /32" core bit is used, 7 the stabiliser should have a 8 /16" OD.

4) 5) 6)

7)

The core barrel shall be run on a stabilised BHA. The stabilisation of the BHA shall be, when possible, the same as used for drilling. Coring, especially in hard formations, requires f ull stabilisation to allow higher weight to be applied to the bit. Higher weight on an unstabilised core barrel can cause jamming, spiralling and flattening of cores.

Note:

Different configurations can be chosen by the Directional Drilling Engineer and/or Coring Engineer.

8)

If required, it is possible to use MWD and the core barrel in tandem, placing the steel ball on the pressure relief plug before running in hole. In this case circulation through the core shoe is impossible.

9) 10)

Do not install a MWD tool on a core barrel in a deviated well with a fractured formation. If a drilling jar is run in the string, the inside diameter of this tool must be compatible with the ball diameter of the core barrel. If the Company Drilling and Completion Supervisor deems it necessary (e.g. presence of iron in the well), a trip with a junk basket shall be made. If the coring point is known, a junk basket can be run in the drilling assembly used to reach the coring point depth.

11)

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0 15

12)

If continuous coring, ream with a drill bit at least every 100ft (27m) if a 8 /32" core bit is used. 1 With the use of 8 /2" core bit this operation is unnecessary.

13)

Take and record the Reduced Pump Stroke Pressure (RPSP) with the core barrel in the hole, after dropping the ball and with it in place.

CORING PROCEDURES

10.3.1. Operating Instructions

The following instructions apply to all sizes of core barrels. Junk

On the last rock bit run prior to coring, ensure that the hole is free from junk, by running a junk sub in the assembly. If any doubt exists as to cleanliness of the hole, it may be advisable to run a reverse circulation basket or magnet, thus ensuring the complete removal of junk off bottom. Tight hole

If it is known that hole problems (i.e. dog legs, tight spots, etc.) exist in the open hole, it is advised that the hole be well circulated and a wiper trip be carried out before coring. Care must be taken to avoid sticking of the core barrel in these problematic areas. Core head selection

Make the core head selection based on previous experience, bit records and formation to be drilled. Drill collars

Firstly, check the core barrel connections are compatible with the drill collars. If not, ensure a cross over is available. Drilling practices dictate that sufficient collars are run to keep the drill pipe in tension and have sufficient weight to place on the bit. Similarly this practice is desirable whilst coring. Stabilisation

As with diamond drilling, it is important that adequate stabilisation be run, keeping the core head steady on bottom, ultimately assisting bit lif e and core recovery. The recommended assembly is, two drill collars, stabilisers etc. This should be strictly adhered to, as the core barrel will be the weakest point of the bottom hole assembly. If drill collar stabilisers are not run, premature failure of core barrel thread connections may occur.

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Circulation

All core barrels are designed to run using various circulation mediums, i.e. air, water, drilling mud, with the variations that t hese materials may have. The volume to be circulated will be determined by mud the type, diameter and depth of hole, pumps and formation. Once an average circulation rate has been established, variations of weight and rotary can be carried out. The flow can also be varied to achieve maximum cleaning and cooling of the core head. Too low a flow rate can be detrimental as the cuttings will not be removed sufficiently quickly from the bit face, resulting in regrinding of the cuttings, slowed penetration rate and possible burning of core head. Too high a circulation rate will lift the bit off bottom resulting in diamond damage. There is also a possibility that loss of core can occur due to washing the core as it the enters bit throat. If this problem is suspected to be occurring when coring loosely consolidated formations, a face discharge bit run with a pilot type lower shoe should be applied. In these situations an emphasis should be made on cutting short cores, as the weight of the core in the inner tube should not exceed the formation strength of the material being cored, reducing again the possibility of breaking down of core and subsequent removal by washing. Loss circulation material

Most core barrels can operate efficiently with LCM. However, care must be taken in the mixing of the material, to avoid large masses of material which could possibly block the core barrel or core head fluid water exhaust. Rotary speed

When starting to core, a slow rotary speed of 40-50rpm should be applied. As the core enters the inner barrel and weight is added, the rotary can be increased. When carrying out a drill off test, the optimum rotary speed can be determined. Check critical drill pipe rotary speeds and avoid rotating in these areas. Through experience it has been found that a safe maximum rotary speed of 150rpm can be applied on core barrels, although in general a rotary speed between 70-120rpm is sufficient to core most formations. Weight on core head

The weight run on the core head will be determined by the size of core head , size of core barrel and the nature of formation to be cored. When coring has commenced the minimum starting weight should be applied. Once core head has drilled a pattern and first stabiliser has entered the new hole, the weight can be increased in small increments (i.e. 2,000lbs) until optimum performance is achieved. Avoid exceeding the recommended maximum weight. Once a satisfactory weight has been reached, it should be maintained and not allowed to drill off. Torque

Excessive or fluctuating torque should be avoided. Torque readings will change with varying formations or excessive weight and rotary speed. If high or fluctuating torque exists, find the correct combination of weight and rotary to achieve as smooth and as steady a torque reading as possible. 10.3.2. Preparing for Coring

1)

Prior to pulling out of the hole for coring, make a short trip to the last casing shoe.

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3)

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Return to bottom, circulate bottoms up and then pull out of the hole. Ensure that there are no restrictions in the string to stop the passage of the pressure relief plug ball. If any doubt exists, a drift of the drill string shall be carried out to ensure the correct passage of the ball. In full hole coring, tripping into the hole shall be methodical. Caution should be exercised at all tight places to prevent the core head from sticking. Tight places must be reamed out by rotating at maximum of 30rpm and using the maximum circulating rate and minimum weight. Reaming of long intervals should be avoided with core heads, as their life can be adversely affected.

4)

When the bottom is reached, make up the kelly and wash down to bottom taking a note of the pressure. When a large amount of fill is encountered, it is advisable to clean to the bottom by circulating out the fill rather than coring it out. Use as little rotation as possible. Wash out slowly picking up periodically and checking kelly measurements with the pipe tally. When the true bottom is reached a weight on bit gain accompanied by a pressure increase should be noted.

5)

Once it is fully established that the bottom has been successfully reached, circulate for a further 10 to 15mins to clean out the inner barrel. Pick up, break off the kelly and drop the steel ball. If necessary space out with pup joints in order to avoid (or minimise) pipe connection while coring. Make up the kelly and pump the ball down at a good circulation rate (allow one minute per 1,000ft). When the ball reaches the pressure relief plug a slight pressure increase should be observed. With the ball in place record the off bottom pressure at the same circulating rate that will be used during coring.

6) 7)

8)

10.3.3. Starting of the Coring Operation

1) 2) 3) 4)

5) 6)

7)

Check the pump strokes ensuring that the correct circulation rate is being delivered to the core head. Lower the core barrel on to bottom and apply a weight of 5,000 to 7,000lbs (2 to 3t). Start rotating, bringing the speed up slowly to 40-50 rpm. When sure that core head has seated, (this should be apparent through pressure increase) maintain the starting weight until approximately one foot has been cored. After cutting the 1ft (30cm) of core, the weight should then be increased in 2,000lbs increments. Increase the rotary speed to approximately 60 rpm. Once 2 or 3ft (0.5-1m) has been cored, the weight and rotary speed can be varied to achieve the maximum performance. In general a rotary speed between 70 and 120 rpm is used to core most formations. Slow rotary speeds are beneficial when coring fractured formations. Using speeds of 30 to 40 rpm produces less disturbance of the core. The pump pressure should now have increased and levelled out. Therefore the pump strokes should be checked ensuring original flow rate is maintained. Take note of pressure and watch it constantly throughout the coring. Pump pressure increases or decreases are an indication that something abnormal is occurring and the cause should be determined and remedied. Make sure the flow rate has not changed due to a variation in SPM, pump malfunction or wash out in the string.

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If the pump pressure increase and the torque decreases, this generally indicates a formation change. If the pump pressure, penetration rate and torque decreases simultaneously, this indicates the barrel has jammed. If the pump pressure and torque increases simultaneously, the core head has probably ringed

8)

The table 10.d shows flow rates given as a general guide only.

9)

If situation is not corrected after a short time, the barrel should be pulled immediately to avoid excessive damage to core head, core barrel or loss of the core.

Hole Size (ins)

1

12 /4 1 8 /2

Barrel Size (ins)

8 3 6 /4

Soft Formation 300/400 160/250

Flow Rate GPM Hard Formation 570/650 280/300

Table 10.D - Coring Flow Rate 10.3.4. Possible Cause Of Pump Pressure Changes

a)

Pressure changes could possibly be due to changes in flow rate, debris in pump valve seats or washed liner. Check the pump strokes and condition of the pump first.

b)

Pressure decreases could be attributed to the core jamming or filling of the barrel. This can occur in fractured or laminated formations, the core being jammed in the inner barrel or core catcher holding the bit off bottom, thus increasing flow area and causing a decrease in pump pressure. However, in soft unconsolidated formations, it has been known for the pressure to increase, indicating that the formation being cored has jammed and is being drilled rather than cored and excess material is plugging the waterways of the core head. Again in soft material the core may jam and no pressure charge be noted. However, the first instance is more likely. Another possible cause could be a wash out in the drill string. In any of these cases it would be advisable to pull out of the hole.

c)

Pressure increase, if the mud volume is constant, it is possible that the core head has ‘O’ ringed, i.e. the diamonds have been damaged letting the formation abrade the matrix, blocking off the fluid course and restricting fluid flow, therefore creating a pressure increase. An ‘O’ ring occurrence can be determined by picking up of the bottom, the pressure should then fall to normal off bottom pressure.

d)

When re-tagging bottom, if the pressure increase is immediate, this confirms that core head damage has occurred.

e)

Another possible cause for pressure increase could be the inner barrel or swivel assembly backing out and sitting on the core head. This can be determined by picking up off bottom, it is most likely in this case that the pressure will remain high. In either case the barrel should be pulled immediately.

f)

Minor fluctuations in pressure could possibly be due to changes in formation, while mud is being mixed or unbalanced mud in the hole after a trip.

10.3.5. Breaking Core (Making A Connection Or Pulling Barrel)

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When it becomes necessary to make a connection, or to pull a full core barrel, the following procedure should be followed: 1) 2)

Stop the rotary table and shut off the pump. Mark the kelly. Pick up the drill string until the weight indicator shows the core spring has gripped the core. Continue picking up until core breaks or the recommended pull is reached. If the core does not break with the maximum strain, then start the pump at normal coring flow rate and hold the pull on the core until it breaks.

3)

After the core has broken, raise the core head 10ft (3m) and then lower slowly back to within one foot of the bottom checking the weight indicator to see if there is any obstruction caused by core left in the hole. If the core appears to be properly caught in the barrel, pick up and pull out of hole if coring is completed or make a connection if coring should be continued. When coring is resumed after a connection, run to bottom without rotary or circulation and add weight approximately 50% higher than normal coring weight. This additional weight should release the core from the core spring, permitting the passage of new core into the inner barrel.

4) 5)

6) 7)

Pick up the drill string until the normal coring weight is reached. Start the pump at the normal rate. Bring the rotary speed up slowly to normal rotation and continue to core. Make sure the pump pressures are normal when coring is recommenced.

10.3.6. Recovery of the Core

The following procedures cover the conventional inner tube. If other inner tube or rubber sleeve is used, the core recovery will be executed by a Coring Engineer. When the core barrel is full or it becomes necessary to pull out of the hole, the following procedure should be followed: 1)

2) 3) 4)

Break the core and pull out of hole. When tripping, care should be taken when setting slips to avoid jarring the barrel as core loss may occur. It may also be advantageous to chain out the pipe whilst in open hole. Special attention has to be paid during tripping in order to avoid pipe sticking. If any drag occurs, rotate the pipe slowly with the slips in. Do not exceed 30,000lbs (15t) overpull. The core shall be recovered under the Company Well Site Subsurface Geologist's supervision.

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1)

2) 3)

4)

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When the core barrel reaches surface place a collar clamp above the slips. Break off the last stand of collars and stand back in the derrick. Remove steel ball from the core barrel using the pick up tool. Make up an elevator sub, and torque up the sub using the tongs. Pull the core barrel out of the rotary table. Break off the bit. Make up a core barrel protector making sure it is tight. Run the core barrel back into the rotary table, a visual inspection of the core barrel and stabilisers can be carried out whilst the barrel is being lowered. Set the slips below the top stabilisers, replace the collar clamp. Break out the safety joint, rotate out using chain tongs, and pull out the inner barrel. Check the inner barrel connection has been pulled. Break off inner tube shoe lower half (catcher) using chain tongs or a pipe wrench. Place the core tong shoe on the inner barrel. The shoe should be backed out on the rig floor preventing core from falling out of the inner tube. Put the core tong handle on the core tong shoe. Exert pressure on the core tong handle and pick up the inner barrel slowly. Remove the inner tube shoe. The core can now be removed from the inner barrel, as the inner tube is picked up. When desired boxing length is reached, exert pressure on the core tong handle. The exposed core can then be removed and boxed. Lower the barrel, keeping pressure on the core tong handle until the core in the core tong is resting on the floor. The pressure on the core tong handle can now be released, pick up inner tube again exposing core. This procedure should be continue until the core marker comes out of the inner tube. If however the core marker or further core does not appear, lower the inner tube onto the floor and knock the inner barrel with a sledge hammer until the core falls. Do not repeat the sledge hammer blows to the same area on the inner barrel as this will damage the tube. If the core can not be removed in this manner it will be necessary to lay down the inner tube and pump out the core. Using the pump out bean and plunger, the core can be pumped out using water as a medium. Do not under any circumstances use pressurised air.

9)

Once the removal of the core has been completed, clean off the catcher and lower shoe, replace if necessary. Make up the lower shoe up onto the inner barrel, tighten with chain tongs using cheater bars. Run the inner barrel back into the outer tube. Check for bearing wear, if excessive change out. Check the ‘O’ rings. If all are in good condition, regrease the safety joint and make up to the recommended torque. Break off the protector. Evaluate the core head wear and change out if necessary.

10)

Make up the core head. Pick up the barrel. Ensure the inner barrel is rotating freely, by placing a hand inside the core catcher and rotating. The barrel is now ready to run into the hole for further coring. In case of continuous coring, ream with a drill bit at least every 100ft (27m) but only if a 15 1 8 /32" core head is used. With the use of a 8 /2" core bit this operation is not necessary. Reaming shall be avoided when using a core barrel. If this has to be done, use the maximum circulating rate with minimum weight and rotate at a maximum of 30rpm.

11)

12)

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Refer to the Manufacturer’s field handbook for assembly of the core barrel and specific coring parameters.

CORING IN DEVIATED HOLES o

In deviated holes (certainly in angles over 20 ), coring is more difficult because of the additional forces caused by the weight on bit, the weight of the core barrel and of the drill collars at such angles. These gravity forces will bend the drill collars and core barrel. As a result the inner barrel will also rotate and the bit will start to wobble. This again will result in poor recovery and unequal wear of the core head. Also the hole angle and direction could be affected. In order to minimise the bending, additional stabilisation is required. It is recommended to use only a 30ft (9m) core barrel, instead of the normal length of 60ft (18m). 1

1

When an 8 /2" core is cut in a larger hole (e.g. 12 /4") and a second run with the core barrel is required, it could be difficult to re-enter the rat hole. In this case it is suggested that the rat hole is enlarged with a bit to the original size first and then run the core barrel again. When long intervals have to be cored a f ull size core head and core barrel will be used. 10.4.1. Stabilisation of the Outer Barrel

All coring in deviated holes must be done with a core head equipped with a piggy-back stabiliser, whenever possible. This will keep the core head stable resulting in a good core recovery. The 30ft (9m) barrel should preferably be stabilised at the top, centre an bottom. These o 15 stabilisers should have wide blades, right-hand spiral 360 wrap with an 8 /32" OD. This means that the two barrel sections cannot be of the standard length, but must be only 13ft long (4m). 10.4.2. Stabilisation of the Inner Barrel

The inner barrel should also be stabilised preferably with a stabiliser in the centre. 10.4.3. Stabilisation of the Drill Collar Assembly

The first string stabiliser must be placed directly on top of the core barrel, followed by a stabiliser at 30ft (9m) and one at 60ft (18m) above the barrel. The remaining available stabilisers should be evenly spaced out over the rest of the assembly, as required.

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11.

LEAK OFF TEST PROCEDURE A Leak-Off Test (LOT) will be performed On W ild-Cat wells at each casing shoe after setting the surface casing. LOTs are also recommended to be carried out on both appraisal and development wells. Leak Off Test and Formation Integrity Test (FIT), also termed the Limit Test, are for formation strength pressure tests made just below the casing seat prior to drilling ahead. These tests are carried out to:

• • •

Investigate the cement seal around the casing shoe which should be at least as high as the predicted fracture pressure for the area. Investigate the wellbore capability to withstand pressures below the casing shoe in order to allow proper well planning with regard to the setting depth of the next casing, mud weights and alternatives during well control operations. Collect regional information on formation strengths and stress magnitude for different applications including optimisation of future well planning, hole stability analysis and modelling, reservoir application.

Prior to a test, a decision should be made to either increase the pressure until leak off occurs (as in the LOT) or to stop at a predetermined pressure for a (FIT). It should be noted that:

• •

FIT does not obtain information on stress magnitude. A LOT is designed and should be performed to determine, in a better way, the desired data without breaking down the formation.

When a Formation Integrity Test is required, the maximum pumping pressure is often expressed in terms of ‘Equivalent Mud Weight’ (EMW): Im perial units EMW =

P 0. 052 x TVD

+ MW

where: P

=

Pumping Pressure (psi)

TVD

=

True Vertical Depth (ft)

MW

=

Actual Mud Weight (PPG)

Metric units EMW

=

P x 10 TVD

+ MW

where: 2

P

=

Pumping Pressure (kg/cm )

TVD

=

True Vertical Depth (m)

MW

=

Actual Mud Weight (kg/l)

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Lots or FITs can be carried out in any open hole section and at any time while drilling the hole, even if it is customary to have it performed some metres (6-15 metres) below the casing. For instance, the casing seat can be in a shale and the first sand formation may be encountered several hundred feet deeper. This will certainly be more permeable than the shale, and a test can be performed to ascertain the maximum pressure this sand can hold. If it is lower than the shale just below the casing seat, this sand becomes the limiting factor. 11.1.

TEST PROCEDURE

Prior to performing a formation strength test, prepare a sheet of graph paper to record pressure versus cumulative mud volume. 1)

Drill out the float equipment, clean the rat hole and drill 5m of new hole.

2)

Circulate a mud quantity equal to the internal string volume plus the new hole plus 50m internal casing volumes. This mud shall be cleaned and conditioned to the density and filtrate as indicated in the Mud Programme to be used for the next drilling phase.

3) 4)

Pull the bit back into the casing shoe. Rig up the cementing unit to the drill pipe. The unit shall be equipped with high precision, low pressure gauges. The range of the pressure gauge shall be selected based on the actual mud weight and the estimated (LOT) or predetermined (FIT) pressure. A pressure recorder should be used during the test. The use of the rig pumps for making these tests are unsuitable.

5) 6) 7) 8) 9) 10)

11) 12) 13)

Fill and test the lines with mud. Break circulation with the cementing unit to make sure that the bit nozzles are clear. Stop pumping when circulation is established. Close the top pipe rams or the annular. Open the annulus of the previous casings. Pump slowly until pressure builds up. Once pressure is established, pump uniform volumes of mud and wait for the pressure 1 to stabilise; flow rates range from /8 bbl/min (20l/min) up to a maximum of 1bbl/min 1 1 (160 l/min), however values of 0.25bbl (12 /4” and smaller holes) or 0.50bbl (17 /2” hole) are commonly used, and wait for two minutes, or the time required for the pressure to stabilise. Note the cumulative mud volume pumped, the final pumping and final static pressure. Repeat steps (9) and (10) above and plot pressure versus cumulative mud volume for each increment of pumped volume. Continue this procedure until:

•

•

Two or three points on the plot are reached where the pressure deviates and falls below the approximate straight line (or if the pressure does not increase with the injected volume). The point on the plot where the curve begins to bend away from the straight line is called Leak Off Point (Refer to figure 11.a). Or the predetermined test pressure is reached.

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15)

16) 17)

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Stop pumping, shut in the well, record and plot pressure versus time until stabilisation (usually it takes 15-20min). In the early stage (2-3min) one value every 15-30sec should be collected while for the remaining a value of pressure every 30-60sec may be sufficient. The use of PACR or an equivalent device, if available, is preferred. Bleed off the pressure and record the quantity of fluid returned into the cementing unit. Compare it to the volume used for the test to obtain the amount of fluid lost to the formation. Open the BOP and calculate the formation strength in terms of ‘Equivalent Mud Weight’ using the lowest between leak off point pressure and stabilised pressure. Collect the data recorded during the test in a data sheet together with the following information: borehole diameter, depth of test, depth and type of the last casing, mud density, plastic viscosity, filtrate and gels (refer to the example on the next page).

Note:

The pumping rate should be kept within the limits described in step 9). If the rate is too low, filtration losses will mask any leakage loss, or, if the rate is too high the formation may suddenly break and the leak off pressure will not be determined. Also, the longer the open hole section, the higher should be the injection rate. If the initial pumping rate is not sufficient, the well should be depressured and the test restarted with a higher rate.

Note:

If a float valve is used in the drilling string, the test can not be carried out by pumping down the drill pipe. In this case rig up the cementing unit to the choke or kill line, fill and test the lines against the fail-safe and establish circulation through the riser. Close the BOP and perform the formation strength test pumping down the annulus.

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SPER 33

0

Report N°

LEAK-OFF TEST REPORT

Date: WELL CODE:

WELL NAME: Open hole depth (m): Hole Diameter (in): Last Csg. Shoe (m): Csg. diameter (in): Grade: Weight (lb/ft): Max. Burst pres (psi): Litology:

825 12”1/4 797 13”3/8 J-55 61 3103 Shale

CONTRACTOR:

Mud Type: Weight (Kg/l): Marsh Viscosity (sec/Qt): P.V.(cps): 2 Y.P.(lb/100 ft ): 2 Gels(lb/100 ft ): W.L (cc/30 min):

RIG NAME:

FWGELS 1.3 44 19 5 2/8 10.5

Expected EMW

RIG CODE:

Rig type: R.K.B. elevation (m): Water Depth (m): Pumps: Liners (in): Flow Rate (bpl):

J.UPs 26 24 12-P-160 6.5” 0.25

2

Kg/cm /10 m

1.68

Time (min)

Volume (bbl)

Pressure (Psi)

Time (min)

Volume (bbl)

Pressure (Psi)

Time (min)

Volume (bbl)

Pressure (Psi)

1 2 3 4 5 6 7 8 8 8.5

0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.00 2.00

50 100 250 380 450 480 520 550 520 505

9 9.5 10 10.5 11 11.5 12 13 14 15

2 2 2 2 2 2 2 2 2 2

490 480 470 463 455 450 445 440 437 435

16

2

435

Note :

Pumped with a costant flow rate of (bbl): Volume pumped (bbl): Volume returned (bbl):

Time

(psi)

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

(min) 19

4,25

4,5

4,75

5

1000 900 800

P re s s ur e

stop pump

700 600

shut in curve 500 400

8 minutes 300 200 100 0 0

0,25

0,5

0,75

1

1,25

1,5

1,75

2

2,25

2,5

2,75

3

3,25

3,5

3,75

4

(bbl)

Flow Rate RESULTS: (Press. mud + Press. L.O. )x10/Depth=[(1.3 x 797 / 10) + (430 x 0.07)] x 10 / 797 = 1.68 (Kg/cm2/10 m) Note:

Company Representative

Figure 11.A - Leak-Off Test Report

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12.

CASING RUNNING AND CEMENTING

12.1.

RESPONSIBILITIES

1) 2)

3)

4)

5)

6) 7)

Grade

The Company Drilling and Completion Supervisor is the person in charge of all casing running and cementing operations. The Company Drilling Engineer should be present on the rig, whenever possible, for the intermediate casing operations and to assist the Drilling And Completion Supervisor during critical phases, providing technical assistance. The Company Drilling and Completion Supervisor shall ensure that all pipe is correctly measured, all equipment is of proper size and type specified in the Drilling Programme and that the most appropriate casing, running and cementing procedures are followed. A detailed programme to include the casing design, stress calculations, string composition, floating equipment, centralisation, special running procedures, cementing calculations and procedures, etc. shall be compiled and available at least three days before operations commence. On the rig only the Company Drilling and Completion Supervisor, assisted by the Company Drilling Engineer, is authorised to change the programme. detailed above. However, consultation with the Company Shore Based Drilling Manager/ Superintendent is advisable, time and work permitting. The Toolpusher, Driller, Cementing Operator, Mud Engineer and Mud Logging Operators shall be given detailed instructions on their duties and responsibilities. The following table 12.a (see API Specification No 811-05CT5) shows the colours and number of bands for each grade of casing. Pipe/Pipe Joints

Couplings

6ft or Longer

J 55

One bright green band

Entire coupling bright green and one white band

K 55

Two bright green bands

Entire coupling bright green

N 80

One red band

C 95

One brown band

Entire coupling brown

P 110

one white band

Entire coupling white

Entire coupling red

Table 12.A - API Casing Colour Coding

A coloured strip three inches wide will be painted on the coupling and a three inches wide stripe on the pipe body within 24” of the end of the coupling.

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12.1.1. Casing Check List

Within a reasonable time prior to the beginning of the casing operation, the Company Drilling and Completion Supervisor and the Drilling Contractor's Toolpusher shall physically check the availability on the rig of all materials necessary to operations. The following check list may be used as a guideline. a)

Casing joints, enough for planned depth with 5-10% excess or a min. of 10 joints.

b)

Float equipment (float shoe, float collar, stage collar back-up are recommended).

c)

Casing compound.

d)

Thread lock compound.

e)

Solvent to clean casing threads.

f)

Centralisers, scratchers, stop collars and nails as per centralisation program.

g)

API casing drift (special Teflon drift is required for CRA casing).

h)

Wellhead equipment (casing spool, slips, packing, wear bushing, etc.) with back-up.

i)

Cementing plug set with back-up.

j)

Casing circulating head (swedge) with thread consistent with casing in use and backup.

k)

Cementing head (multiplugs with indicating flag).

l)

Casing power tong with back-up and power unit.

m)

Casing manual tongs.

n)

Casing slip-type elevator and spider.

o)

Casing single joint elevator.

p)

Casing hand-set rotary slips.

q)

Casing thread protectors (klampons).

r)

Cement.

s)

Water.

t)

Mud volume (also considering the case of a displacement without returns).

u)

Cement additives.

v)

Diatomite, bentonite or whatever needed if light slurry should be mixed.

w)

Chemicals to prepare spacers, if required.

x)

Inner stinger and centraliser, if required.

y)

Handling equipment (pick up slings, manila rope, etc.).

z)

Torque monitoring system (required for Corrosion Resistant Alloy casing or 7" casing).

aa)

Casing stabbing guide (for premium connections and production casing string).

bb)

HP hose or chicksan line for circulating or reciprocating casing (minimum 15m length).

cc)

Pick-up the casing unit.

dd)

Dope applicator (for Corrosion Resistant Alloy and production casing string).

ee)

Special handling equipment (nylon pick up slings, wooden cover for pipe rack and Vdoor, etc.) required when Corrosion Resistant Alloy casing should be run.

ff)

Casing suspension equipment (surface, mudline, subsea).

12.1.2. Preparation For Casing Running And Cementing

1)

A non-destructive test (NDT) on the casing shall be carried out at a service contractor’s

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2) 3) 4) 5) 6)

7) 8)

9) 10) 11) 12)

13) 14) 15) 16) 17) 18) 19)

20) 21) 22) 23)

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workshop or at the Company’s Operating Base. Casing shall be accurately measured and drifted. Each joint shall be drifted with on API drift or a specially built drift in case of non-standard casing. The joints will be counted and each joint numbered. The joints to be excluded from the string will be clearly marked. A special mark for defective joints will be used and specified in the manifest for back loading. Crossover joint thread connections should be drifted and checked for thickness and correct thread type. Threads should be cleaned with a high pressure stream of water or an evaporating solvent such as Varsol, otherwise manually cleaned on API connections.. Diesel left in the thread roots can prevent the thread compound from forming an ef fective seal. Casing shall be visually inspected to check it is not damaged by hooks used in the box and pin ends while handling. The box thread of the casings should be greased on the rack. API modified thread compound (torque transmission factor = 1) shall be used. table 12.b shows the friction indices for various thread compounds. The float equipment and casing accessories will be inspected. The shoe will be made up on the pipe rack using a thread locking compound. The collar should be made up on the box end of the pipe on the rig floor. Install blank thread protectors on the box ends of shoe joints. The joints between shoe and collar couplings should be loose otherwise spare couplings should be ordered to provide a means of thread locking both sides of the couplings. The centralisers should be made up on pipe rack as per the programme. Wellhead equipment will be inspected, checking all dimensions. Ensure that the cement plugs are compatible with the inside diameter of the casing string. Casing power tongs and associated equipment shall be visually inspected to ensure it is of proper size and condition. The drill line shall be cut and/or slipped prior to running casing, regardless of its condition. Links, elevators, hook assembly and drawwork brakes shall be inspected by Magnaflux prior to running heavy strings. Make sure that the mud pumps are in good mechanical condition and fitted with proper size liners. Verify that shear pins are the correct size and are installed in the pump relief valve. Verify the mud pumps volumetric efficiency to ascertain the practical value of litres/stroke during displacement. Check the correct operation of the pumps stroke counters. The cementing unit should be overhauled a few days in advance of requirement to reduce the risk of mechanical/hydraulic failure during cementing operations. Cement lines, silos, surge tank, air compressor should be checked.

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1)

2)

3) 4) 5)

6)

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Good practice when unloading cement is to blow the first few sacks of cement through the lines in order to prevent moisture contaminated cement from collecting in the tanks. Off-loaded cement should be blown into empty, clean tanks. If possible, avoid storing cement for long periods. Alternate tank usage systematically and check them. Cement will pack when stored for a long periods and it should be aerated for half hour once a week. To prevent condensation in the cement tanks and lines, pressure should be maintained on the system at all times. This will prevent breathing which can lead to condensation. The Company Drilling and Completion Supervisor is directly responsible for the proper inventory of cement and additives required before each job. It is necessary to send a sample of cement, mud, barite and mixing water to the Company Drilling Office where it shall be tested. Check the drill water for chloride content, calcium and pH. Prepare graph, one with casing weight in mud versus depth and the other with steel displacement versus depth. A copy of these graphs must be given to the Driller and to the Mud Engineer.

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AGIP Iglea (API 5A2 Modified ) Bestolife 270 Houghton Stap Pb 6 Houghton Joint N. 1 Jet-Lube Tef Kote (made in UK) Jet-Lube API Modified (made in UK) Jet-Lube Polar (made in UK) Molykote HSC (MS) Shell API Modified Compound Shell France Modified Thread Compound Shell Myrina S 7715 Shell Lub 179 A Shell Lub 179 B Techlube TL 60 Zn

1 1 1 1 1 1 1 1 1 1 1 1 1 1

Baker Seal Bestolife Honey-Koat BP Energrease AS 13 BP AS 11 Houghton Stap Zn 6 Jet-Lube 21 Jet-Lube Kopr-Kote (made in UK) Jet-Lube TF-15 (made in UK) Jet-Lube TF-25 (made in UK) Jet-Lube TF-65 Pb (made in UK) Jet-Lube TL-60 Z 15 (made in UK) Liquid O-Ring 104 Research Laboratories API Modified HP 300 Shell HP API Modified (Shell Oil Co. Code 72732) Shell HP API Modified (Shell Canada Ltd Code 504-599) Shell HP (Japan) Techlube API Modified Thread Compound Techlube TL 65 Pb Thredkote 706 Thredkote 709

0,60 0,70 0,75 0,80 0,70 0,70 0,85 0,90 0,80 0,70 0,80 0,70 0,85 0,80 0,80 0,85 0,70 0,70 0,85 0,75

Jet-Lube SS 30 (made in UK) Molykote HSC Shell S 982

1,15 1,20 1,30

Bakerlok (Thread Locking Compound) Gelokote T 7.285 (Thread Locking Compound) Halliburton Weld-A (Thread Locking Compound) Thread Lock (Thread Locking Compound)

1,60 0,70 0,90 0,60

Table 12.B - Relative Friction Indices for Various Thread compounds

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12.1.3. Installation Patterns (For Mechanical Cementing Aids)

The selection of the proper installation pattern for mechanical cementing aids i.e. centralises, scratchers, turbolisers, etc. is essential to optimise casing running and cementing results. Cementing aids and their installation pattern are a function of operational conditions and cementing objectives. Because of these variable factors, pattern philosophy is different from case to case. The Drilling Programme must specify type, quantity and installation pattern of mechanical cementing pieces, with due consideration to eventual modifications after caliper log evaluation. The following cases described below are shown in figure 12.a and f igure 12.b Case I

The simplest and most practical is the installation of centralisers directly over stop collars. Installation on the racks is advisable as it saves time. This pattern is not recommended in 1 " close-tolerance conditions, i.e. saves 7" rig casing in an 8 /2 hole. Case II

In close-tolerance conditions, the centralisers should be positioned between two stop collars. This pattern may be installed on the rack. Case III

In this alternate close-tolerance pattern, the centralisers are installed between a stop collar and the casing coupling. This pattern allows limited centraliser travel and requires only one stop collar per centraliser, reducing equipment cost. Installation should not be performed on the rack. Case IV

Centralisers can be installed over the casing coupling but this reduces annular flow and the positive stand-off provided by the casing coupling and requires extra rig time. Weatherford do not recommend this pattern for close-tolerance conditions or where ST-I and/or SP-I bows are used. Post Plug Pattern

This pattern (Refer to figure 12.b) is recommended throughout the entire cement column to promote improved cement-to-formation bonding in strings where casing can be reciprocated in 30 to 40ft cycles. The post-plug pattern uses at least one centraliser per joint and free-tomove scratchers, separated by stop collars installed approximately 10ft (3m) apart. The Modified Post-Plug pattern requires two centralisers per joint in conjunction with multiple scratchers and stop collars placed 5ft (1.5m) apart. Wellbore wipers can replace the scratchers for particular applications.

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The following codes will be used to describe the number of centralisers per casing:

• • •

1C: one centraliser per joint 2C: two centralisers per joint 3C: three centralisers per joint.

The following codes will be used to indicate the centralisers spacing:

• • •

C1: one centraliser each joint C2: one centraliser every two joints C3: one centraliser every three joints.

Example : 2C3 = two centraliser every three joints. 1) 2) 3)

4) 5)

6) 7)

The use of spiral centralisers is recommended in each of the patterns where closetolerance conditions exist. Alternate left/right handed spiral centralisers are used in special applications e.g. liners, deviated wells, production strings, improvement of hydraulic displacement, etc.. For open hole intervals, spiral bow type centralisers will be used unless otherwise specified. Straight type bows will be used for wash-out sections, unconsolidated formations, etc. Rigid type centralisers (Positive) are never allowed to enter open hole intervals. In deeper wells, where high-rating casing equipment is used, Positive type centralisers OD for free passage through clamp's slips should be considered. If not applicable, spring bows are recommended and also in casing to casing intervals. Maximise centralisation when special equipment/tools/zone are predicted i.e. stage tools, liner hanger, ECIP, GOC, WOC, etc. Special CRC stop collars, (without nails) are essential for CRA (Corrosion Resistant Alloys) casing.

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CASE I: Over stop collar

CASE III: Between coupling and stop collar

CASE IV: CASE II:

Over coupling

Between stop collars

Figure 12.A - Casing Installation Patterns

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2CPP Post Plug Pattern

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2CPPM Modified Post Plug Pattern

Figure 12.B - Casing Installation Patterns (Cont)

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12.1.4. Preliminary Operations

1)

After open hole log, a trip to bottom is recommended to condition the hole and mud. The Mud Engineer shall check and, if necessary, adjust the mud properties. Plastic viscosity, yield strength and weight shall be kept as low as possible. 2) There is a difference between the driller's and logging depths, strapping in or out of the drill string shall be considered. 3) Check the weather forecast to ensure conditions be such as to allow safe operations. 4) Replace the upper pipe rams with the correct size of rams for the casing to be run. A pressure test of the bonnet and rams seals shall be performed when the pipe rams are changed. 5) Retrieve the wear bushing. 6) Do not lay down the BHA unless unavoidable. Before running 7" casing, break-out BHA and 5" DP. While waiting on cement lay down the BHA and 5" DP. 7) From the caliper log determine the correct volume of slurry, spacers. Centralisation pattern to be used. 8) Verify that the differential pressure between the slurry and mud does not exceed the casing collapse rating. Also make sure that the density of slurry and the planned top of cement do not cause losses of circulation and/or gas migration while waiting on cement. The Company Drilling Engineer, if on site, shall assist the Company Drilling and Completion Supervisor. 9) The Company Drilling and Completion Supervisor, Company Drilling Engineer (if on site) and Cementing Operator shall conduct individually, calculations for the cementing job prior to running the casing. The figures/calculations shall be compared in order to ascertain final cement, volumes, etc. 10) Calculate the maximum allowable overpull while running casing. 11) 12) 13) 14)

Landing joints are to be inspected and selected to avoid interference with wellhead. The coupling must be minimum a 2m from casing hanging point. Do not start running the casing without the Cementing Operator being on site. The operator will start the unit pumps and check for system malfunctions. Check the length of elevator links several days in advance for fitness with equipment i.e. spider, circulating/cementing heads, circulating casing packer. Before commencing of the job, the Toolpusher, Driller, Cementing Operator, Mud Engineer and Mud Logging Operator shall be fully informed of the cementing procedure and given the f ollowing data:

• • • • • • • • • •

Total amount of lead and tail cement slurries. Volumes, density and composition of spacers. Calculated top of tail and lead slurries based on hole conditions. Desired density of lead and tail slurries. Required amount of mixing water for both slurries (fresh or sea water to be duly noted by all concerned). Total amount of cement to be used. Required volumes of additives for both slurries. Estimated setting time of the cement. Internal volume of casing from top to float collar and number of rig pump strokes to bump the plugs. Volume of casing from float collar to float shoe and number of rig pump strokes for overdisplacement only.

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•

15) 16) 17) 18) 19) 20) 21) 22)

Maximum allowable displacement rate compatible with the MAASP. Install centralisers as per the Drilling Programme when the casing is on the pipe rack, in order to avoid time wasting during casing running. Check shoe and collar integrity. Test the sealing adapter 30"-20" shoe for perfect fit. Record initial pit levels to establish a reference volume in order to detect any abnormal condition while running the casing. Arrange an appropriate length of high pressure flexible hose for casing string circulating down and/or reciprocating. Centre the travelling block with the rotary table to facilitate casing running and hanging. Check subs, crossovers, stage collar, ECIP for correct threads, dimensions, etc. Visual inspect the casing internal surface on the pipe rack to ensure that all joints are free from foreign matter.

12.1.5. Running Procedure

1) 2)

3)

4) 5) 6)

7)

8) 9)

A circulation sub, fitting the casing thread, equipped with a WECO connection, shall be readily available on rig floor at all times during casing running. Pick up the shoe joint and remove the blank thread protector at V-door. Lower the joint through the rotary and visually verify for back flow. Fill the joint with mud, then pick up to check for flow through. 3 5 Generally a float collar shall be run two joints above the shoe in 13 /8" and 9 /8" casing and three joints above a 7" shoe. 30" conductor pipe, after drilling of 36" hole, and 20" surface casing shall be cemented using a drill pipe inner string with a sealing sleeve adapter. Use thread lock compound on all the connections on and below the float collar (or landing collar). Pick up the collar joint and remove the blank thread protector at the V-door. Make up the joint and fill with mud. Pick up and check the shoe and collar for flow through. After running 6 joints, make up the circulating head and test the float equipment pumping at the maximum displacement rate. Record pressure losses due to collar and shoe at various flow rates. When running Buttress casing, make up the first 10 joint connections to the reference triangle (do not consider the joints between shoe and collar since the torque transmission factor of thread lock compound is not the same value as casing dope). Record the average torque required for these first joints and use it for the remaining part of the string. The torque value shall then be checked every 10-20 joints and adjusted, if necessary. When running other threads, the make up torque should be in accordance with the manufacturer's specifications. Rotary slips with safety clamp and side door elevators may be used up to a weight equal to 60% of the rating for the elevators. Beyond this weight, use slip power elevator and spider.

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10) 11)

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Slip power elevator and spider shall always be used when running casing in open hole).

Stop the block before setting the spider and then slowly slack off pipe weight to minimise pipe slippage, notching or crushing. The maximum casing running speed should be calculated for the well specific mud properties and formation integrity. As a rule of thumb, running speed should never exceed 0.6m/sec. (20sec/joint) inside casing and 0.3m/sec. (40sec/joint) in open hole.

Note:

For 7" casing the running speed shall not exceed 0.2m/sec. (1 joint every minute).

Inform the Driller that speed variation is a cause of surge and possible mud loss, so it is particularly important to run the casing in as smooth a manner as possible. 12) 13) 14)

Fill up the casing after every joint and completely every 10 joints. If running a liner, fill up the running string at each stand. While running the casing compare the actual string weight and pit level, with theoretical values previously plotted, in order to detect any possible abnormal condition. Intermediate circulation is generally not necessary, however it may be advisable under the following circumstances:

• • • •

When the weight indicator shows excessive dragging or a tendency to stick. When an excessive amount of mud cake, cutt ings or shale is expected. When it is anticipated that returns will be lost if excessively high pump pressure is required to break circulation at bottom. At the previous casing shoe.

Circulation should start at a very low pump rate increasing gradually to the maximum displacement rate. Record the circulating pressures at the various rates. 15)

16)

17)

18)

19)

When installing a production casing string it is recommended to place a short joint near the pay zone to aid in checking depths with casing collar locator (CCL) during later logging operations. During casing running, plot the casing weight and pit levels on the graph (described earlier) and compare them with the theoretical values previously plotted to detect any possible abnormal condition. At the previous casing shoe depth fill up the string completely and circulate the volume inside the casing. Check levels and start circulation at a very low pump rate increasing gradually up to the maximum allowable displacement rate. Record the circulating pressures at the various flow rates. Space out the casing string in order to have the cementing head at a convenient height. On the other hand, ensure that the last casing collar is not across the hanging point. With the casing at TD circulate the total hole volume, following the procedure in step 17).

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During circulation, check the levels and any bottom cushion. At the end of circulation, record the pressure with the estimated displacement rate. During the final circulation and the f ollowing cementing job phases, hang the casing on the travelling block and do not leave it on the rotary table clamp.

Note:

In particular instances the ‘Post Plug’ technique should be used in order to reciprocate the casing string.

12.1.6. Casing Operations With A Top Drive

With the introduction of 500 tons bails and adequately rated swivel, the Top Drive is rated at 500 tons for casing operations. Longer bails (132” or 144”) must be used to allow clearance for the casing elevator under the torque wrench in the pipe handler. Also clearance for the cementing head must be taken into consideration when determining casing bails length. By attaching a short piece of hose to the saver sub in the pipe handler, the casing can be filled while lowering by using the remotely controlled kelly cock to st art and stop the calculated filling flow. If desired, casing can be run conventionally using the block and hook by swinging the Top Drive aside. Very long bails must be used to prevent the block from contacting the Top Drive dolly. 1

It is recommended to prepare landing/circulating heads (4 /2" If Box connections) connected 3 5 directly to top drive for 13 /8", 9 /8" and 7" casing, in order to facilitate circulating down, casing reciprocation, casing retrieve with circulation, etc. Circulating Casing Packers compatible with top drive systems are available in the market (i.e. Weatherford, PBL, CTC, TAM, etc.). 12.2.

CRA CASING OPERATIONS

Pre-job meetings for running CRA (Corrosion Resistant Alloys) must be held between the Eni-Agip Drilling Representative, the Thread Inspector and the Casing Make up Supervisor to discuss the procedures and responsibilities of the operations and the make up criteria as detailed in (STAP-A-1-M-1002).

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12.2.1. Preliminary operations

1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11)

Prepare and double check the tally list. CRA casing should be set on racks to allow enough space for a 360° revolution for cleaning and inspection. Ensure drift mandrels conform to API requirements or the manufacturer’s specification (Teflon drifts are recommended). Always have clean thread protectors on the connections when moving or handling pipe. Have red and yellow paint available for marking rejected and repairable pipe. Ensure the accuracy of the torque/time/turn recorder when running CRA casing. Always use a stabbing guide to assure the connection is stabbed with no thread or seal damage. Ensure that the correct sized and serviceable tubular safety clamp is available for first few joints. Protect the areas CRA casing when is moved with wooden cover (‘V’ door, ramps, rack, etc.). The use of antifriction spray is recommended in conjunction with Modified API Dope. Ensure the dope is thoroughly mixed. Special CRC stop collars (without nails) are imperative for CRA casing as well as ‘non marking jaws’ on the power tongs.

12.2.2. Handling and running CRA tubulars

1)

Do not use lift hooks to pick-up CRA pipe. The joints should be lifted to the ‘V’ door by nylon slings.

2)

The elevator must be placed on the pipe only after the joint is made-up.

3)

A safety clamp will be securely placed around the joint located in the slips to prevent slippage (X-line or flush coupling). Keep thread protectors on the Pin and Box until stabbing to avoid loose scale or debris interfering with the make-up. The use of an integral back-up power tong is recommended with a connection monitoring system. The equipment must be capable of providing an instantaneous view of torque versus time and turn, which provides a hard copy. A dump valve must be used to prevent over-torque. Final make-up of the pipe will be at a low speed only and held for +/- 3 seconds to ensure the plateau effect on the time graph.

4) 5)

6) 7) 8) 9)

Any premium connections failing or exceeding the required make-up criteria shall be rejected. A maximum of three attempts only must be made. Threads, protectors and compound must be absolutely clean, free of grit, scale, or powder. For premium connections, the initial spin-in should be about 10rpm and the final makeup between 1 to 3rpm. A dope applicator and antifriction spray are recommended for use on production strings designed for gas well.

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Item Casing Power Tong

Notes Provided with relevant power unit.

Back-Up System

To avoid bending and shearing forces on casing. Controlled Make-Up System To automatic drop the speed of the tong before reaching the shoulder. Non Marking Jaws To eliminate die marks. General Handling Equipment Single joint elevator Lifting sub Nylon lifting sling Elevator Rotary handslip Spider elevator Stabbing guide Manual chain tong Safety clamp Strap Wrench For hand make-up Pick-Up And Lay-Down On-shore wells Machine Drift Aluminium or Teflon Klepto Thread Protector Computer Controlled MakeUp Service Lubricant Applicator Single Joint Compensator

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Selection/ Specification Selection shall be based on desired make-up torque and casing size. It is a casing power tong optional.

It is a casing power tong optional.

It is a casing power tong optional.

Selection shall be based on casing size and weights Air inflatable thread protectors or Selection on casing sizes and similar. thread types. Recommended for CRA. casing.

It provides positioning control and weight compensation while stabbing.

Suggested for CRA. casing. Suggested for CRA. casing.

Table 12.C - Casing Running Equipment

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CEMENTING AND DISPLACEMENT PROCEDURE

12.3.1. Single Or First Stage

1)

Line up to the rig pumps. Break circulation slowly. When it has been determined that full returns have been established, gradually increase the pump rate and circulate total hole volume. Record the pressures at the various flowrates. At the end of circulation, record the pressure with estimated displacement rate. 2) During circulation monitor pit levels, bottoms-up mud properties and eventual shows. 3) After bottom circulation, line up the cement head to the cementing manifold. 4) Check the cementing lines and connect the cementing manifold to the rig mud pumps. All lines of the cementing manifold shall be flushed with water and pressure tested to 5,000psi prior to cementing. 5) The Mud Engineer shall record initial pit levels. He shall be present at the mud pits during the whole cementing and displacement operations reporting any loss on returns, pertinent facts and data. 6) Pump the spacer. Unless the effective mud density required to control formation pressure dictates otherwise, all cement jobs shall be flushed with a water spacer. The spacer volume shall be equivalent to, circa three minutes of contact time. The use of other particular spacers, related to mud weight and system in use, will be specified, in the drilling programme (contact time, compatibility with cement slurry, etc.). 7) In all cementing operations, a top and bottom plug shall be utilised unless otherwise specified in the Cementing Programme, 30” and 20” casing will be cemented through an inner string. 8) The use of non rotating PDC drillable plugs are recommended to enable further drilling phases. 9) In advance to the cementing job, the water and cement shall be checked to ascertain that the chemical characteristics are the same as the samples used in the pilot tests. 10) Mix the cement to the required slurry weight and have the weight checked regularly. A pressurised mud balance is recommended in order to reduce any air entering the system to a negligible volume. The use of this tool provides advantages:

• • 11)

12) 13)

A fluid density value that is virtually the same as that under actual downhole conditions. The correct water/cement ratio. It must be noted that changing the W/C ratio, means the amount of additives in the slurry also change.

When mixing cement, samples of slurry shall be collected in numbered containers, taken at the start, middle and end of each type of slurry. Also take water, mixing water samples and one sample of dry cement from each tank used. For the slurry recipe follow the Cementing Programme. Leave the mixing tube full of the required weight slurry at the conclusion of mixing to avoid the possibility of pumping diluted cement or possibly water into the casing before the top plug is released.

14) 15)

Flush the cement from the lines prior to releasing the top plug. The Cementing Operator shall personally release the top plug and the Company Drilling and Completion Supervisor shall personally witness the process.

16)

Switch over to the rig pumps. The cement pumping unit shall be ready, waiting to take over in case of any malfunction or in the event pressure becomes excessive for the rig

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17) 18) 19) 20) 21) 22) 23) 24) 25) 26)

27) 28)

0

pumps. Displace the cement with mud at the maximum permissible rate and surface pressure, unless otherwise stated in the Cementing Programme. Slow the pumps, if there is a loss of returns during the displacement, to regain circulation. If returns cannot be regained, continue to displace the cement at the lowest permissible rate (unless otherwise advised) record the returns. Stop displacement only in the event the pressure exceeds 70% of the casing burst pressure or 5,000psi, whichever is least. Reduce the flow rate at the end of operation to avoid any sudden pressure surge when bumping the plug. Bump the plug, pressure up to conduct the casing pressure test. Release the pressure gradually as soon as possible to avoid the microannulus effect. The bumping pressure values are always given in the Drilling Programme. Should the plug not bump, never overdisplace more than half the shoe truck volume (between collar and shoe). Check for back flow to ascertain if the float equipment is holding. If the float equipment fails, shut-in the well by closing standpipe manifold a period at least long enough for thickening. Monitor the pressure gauge so that required pressure can be maintained by bleeding excessive pressure periodically. In this case, the pressure remaining must not exceed the observed differential pressure between the mud and cement. The displacement procedure for 30" CP and 20" surface casing is as follows:

• •

• •

29) 30)

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The displacement volume should be approximately 1 bbl less than the theoretical volume. Check for returns. If the floating equipment is holding back pressure, pick up the stinger, circulate and retrieve inner string. If floating equipment is not holding the back pressure, pump the volume bleed back plus 1 bbl, fill up the annulus (required), hold the pressure on the inner string and wait on cement. Keep the annulus under control to be sure that seals are holding the pressure. At the end of this surface casing cementing job, carefully wash the annulus between the CP and the surface casing to at least 5m below the seabed, in order to allow well abandoning operations making the seabed free from any obstructions.

Record all mixing, displacing and bumping operations on a pressure recorder. Consider the option of reciprocating the casing during and after the cementing job to maximise the bonding performance.

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Mud

0

and Slurry

Top Cementing Plug Plug Releasing Pin

Bottom Cementing Plug Plug Releasing Pin

Slurry Plug Releasing Pin

Spacer

Original Mud

Float Collar

Centralisers

Float Shoe

Figure 12.C - Typical One-Stage Primary Cement Job

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Displacing

Displacing

0

End of Job

Plug Releasing Pin Out

Displacement Fluid

Figure 12.D - Typical One-Stage Cement Job(Cont)

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12.3.2. Dual Or Second Stage

1)

The appropriate position of the stage tool in the casing string is always given in the Drilling Programme. Drop the bomb (opening plug) immediately after the first stage cement job according with floating equipment. Record the opening time.

2) Note:

3)

4)

5)

6) 7) 8) 9) 10) 11) 12) 13) 14)

15) 16) 17)

In relation to the drift angle of a directional well, mud density and mud rheological properties, heavier bombs may be selected.

Open the stage collar. Follow the manufacturer's procedure for the stage tool opening pressure and approximate bomb landing time. If diff iculty is experienced in opening the stage collar occurs, re-check the pumping circuit and relevant valves before a final decision is made to reduce the tension on DV sleeves by slacking-off weight of the hook. With the stage collar opened, start circulation with a low pump rate, keeping the mud level under control. Increase the pump rate only when it is certain that no cuttings or cement contamination will cause bridges and compromise the circulation due to fracturing below the stage collar. Circulate a volume equal to the total open hole capacity from the stage tool to surface, checking the eventual excess cement slurry returns. During circulation and after bottom's up, record the pressures at each different flow rates. The bottoms up must be analysed with a gas detector, if the are gas-cut keep circulating until normal again. If necessary, wait on cement for the first stage cement slurry. Prepare for the second stage cement job as per the Cementing Programme. Perform the second stage operation as soon as the cement setting time of the first stage is complete (at least twice the thickening time). A Lab only test is recommended. Arrange the by-pass manifold at the rig floor with double lines (pumping and reversingout). Keep the casing in tension with the slip elevator as required by casing hanging calculations (Refer to the Drilling Programme). Prepare the wellhead (with partially made up bolts) and BOP lifting system to quickly hang the casing string after the second stage cement job. With the mud well balanced, insert the closing plug into the cementing head. Check the stop pin, indicating flag and the circulation manifold. Pump the first cushion and pump the cement slurry. Launch the closing plug and verify its release. Displace the slurry with a pump rate in accordance with the Cementing Programme and previous circulation tests. Make sure that the hydraulics of annulus are correctly considered to avoid fracturing (if a stage tool-packer is not provided). Configure the surface mud system to recover the excess cement slurry, spacer, contaminated mud. Close the stage collar with the pressure advised by the manufacturer’s instructions. After pressure testing, gradually bleed off the pressure. Wash through all the inlets in the wellhead and BOP stack with water.

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Circulating before first stage

Dropping opening bomb

0

Displacing cement for second stage

Stage tool closed

Closing Plug

Opening Bomb

Stage Collar

Seal-Off Plate

148 OF 234

First-stage Plug

Float Collar

Centralizers

Float Shoe

Figure 12.E - Two-Stage Cement Job (single plug system)

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Displacing cement for first stage

Shut-off Plug

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Dropping opening bomb

Displacing cement for second stage

0

Stage tool closed

Closing Plug

Opening Bomb

Stage Collar

First-stage By-pass Plug Shut-off Baffle

By-pass Baffle Float Collar

Centralizers

Float Shoe

Figure 12.F - Two Stage Cement Job (double plug system)

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12.3.3. Double Stage Cementing In Deep Wells Casing hanging after the second stage, while Waiting On Cement (WOC)

When a cement job programme does not require the return of the slurry up to surface, the hanging is performed after the second stage cement slurry thickening time, then it is possible to disconnect the BOP stack maintaining annulus control. In deep wells, where the casing string must be cemented to surface, it may become difficult to work on the wellhead when the slurry is nearly hardened, for the following reasons:

• • • •

The casing is often out of centre and it is difficult and time consuming to insert the slips. The slurry at surface prevents movement of the casing when trying to centre it. Even though they can be placed in their recess, the may slips only lean against the casing without tension, and therefore the casing might be released. In case of a microannulus forming or gas channelling through the cement slurry, pressure in the annulus prevents BOP stack lifting.

Therefore, although this routine complies with safety rules, it does not guarantee a perfect casing hanging operation. To overcome this potential problem, the use of a stage toolpacker is recommended to ensure an annular seal and/or the casing hanging operation has been completed before slurry setting. Casing hanging before the second stage waiti ng on cement.

This procedure offers the following advantages:

• • •

The slurry is still in the fluid state and it is possible to hang the casing. Centring operations are easier because it is still possible to move the string sideways. The BOP stack can be nippled up because primary well control is assured as long as the thickening time has not elapsed.

Since it is necessary to nipple up the BOP stack before cement slurry setting, the nippling operations would have to be carried out quickly. However, this technique is discouraged. As the primary annulus control is missing when the operational time exceeds the programmed or when the slurry thickening time was not precisely predicted. However, secondary control is also limited as the BOP is lifted during WOC. In fact, several incidents have occurred which entailed a loss in rig time and increased costs. Casing hanging before the second stage cementing

The points discussed above show there is an opportunity to hang the casing before the second stage cement job, adopting the use of a special designed base flange or a modified 1 3 casing spool with four 4 /16" outlets instead of the normal two 1 /4" ones). In this case, well control, which is impossible during lifting of the BOP stack, is implemented, since the annular hydraulic conditions are restored after the mud circulation through the Stage Collar. Therefore, the BOP stack is lifted and the casing is hung in a controlled condition.

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This operation can be performed without hurry or worry over premature cement hardening, use of quicker slurries, the lengthening of operating times, mistakes in lab tests, etc. It is also possible to set the slips without problems or obstacles due to the presence of the slurry at surface. There is the further advantage of being able to apply overpull to the casing even if the second stage cement job has not given the proper results. There are no casing movements during the cement slurry hardening time, therefore the possibility that a microannulus is formed is very remote and hydraulic sealing and cement job quality are improved. The practical advantages are as follows:

• • • • • • • • 12.4.

The base flange and the first casing spool, specially designed with larger side outlets, provide slurry displacement with practically no pressure losses. The slips are inserted correctly around the casing holding tension. There is no risk that, casing hang off may be prevented by not being centred. Nippling up operations are carried out at ease and, on the average, quicker, with reduced possibility of mistakes being made due to haste. The well is under total control, especially when the slurry hydrostatic load decreases during WOC. There is greater certainty of obtaining hydraulic sealing during the second stage cement job and during well production life, as the slurry sets while the casing is already under tensile load and is steady. It is possible to use accelerated slurries when gas bearing layers have been drilled. The gas migration may possibly be prevented by subjecting the annulus to pressure, since the BOP stack is always available during WOC. It is possible to displace the slurry through a modified flange with returns to the pits.

MUDLINE SUSPENSION PROCEDURES

12.4.1. Cementing 20" Surface Casing (With Inner Strings)

1) 2)

Run all the 20" casing in the hole and stab on the landing ring. Run the inner string into the casing down to the shoe.

3)

Run the two 2 /8" tubing strings into the 20”-30” annulus. Tag the landing ring and wash out with sea water. At the same time, make up the cementing line and fill-up the 20" casing 5" DPs annulus with sea water. Break circulation and check if the stinger ‘O’ rings are sealed. Pressure test the cementing line and cement the 20" casing as per the Cementing Programme.

4) 5)

6) 7)

3

When contaminated mud is being circulated out, start washing with sea water through 3 the 2 /8" tubing and continue the cementing job or the displacing through the inner string. Once the cementing job is complete, check for back-flow from the inner string and pull out of hole. 3 Pull the 2 /8" tubing strings and rig-up the 20" circulating head.

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1) 2) 3)

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Unscrew the running tool with right hand torque. Open the wash-out ports and wash the mudline hanger (MLH) through the wash-out ports. Screw-back the running tool back up with the correct make-up torque. Pressure test the seals at a low pressure.

12.4.2. Cementing Casings With Plugs

1) 2)

Cement the casing in a single or in dual stage as per previous sections. Disconnect the cementing line at the rig floor, keeping the cementing head connected to the running string.

3)

To assure that there is no cement in the annulus above the running tool, follow the procedure listed below for hangers equipped with wash ports.

• • • • 4) 5)

12.5.

Record the hook load to support the weight of the running string. Adjust the tension to the free point (neutral at t he hanger threads). Rotate the running string to open the wash ports in the hanger. Reconnect the cementing line to the cementing head and circulate out all excess slurry. Continue until the annulus is clean. Disconnect the cementing line.

Rotate the running string, in the opposite direction, measuring the downward movement of the running string. Energise the seal. Reconnect the cementing line and pressure test the casing and running tool.

POST-CEMENTING OPERATIONS

1)

If mechanical problems (lost circulation, etc.) is experienced during the cementing job, or any doubt arises about cementing results a temperature survey or CBL/CET shall be run in order to verify the cement job quality. Temperature survey shall be run after 8 hours WOC and a CBL/CET shall be run after a minimum of 24 hours WOC (48 hours are recommended).

2)

During WOC the following preparations shall be performed to set casing on the slips:

• •

Prepare slings to hang off the BOP stack. Prepare the wellhead equipment required for slip setting and f langing up.

After WOC proceed as follows:

• • • • • •

Disconnect the kill and choke lines. Disconnect the flange required to set the slips. Raise and hang off the BOP stack. Set the casing on the slips with the desired tension (Refer to the Drilling Programme), making sure that the slips are properly set. Cut and retrieve the casing. Nipple up the new casing spool.

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4)

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0

When drilling out a liner hanger, cement and floating equipment, with a stage tool, the following precautions shall be taken:

• •

5)

While drilling cement inside the casing, do not exceed 50rpm and 2-5t WOB. While drilling the underlying formation and until the stabilisers are out of the casing shoe, do not exceed 50-70rpm and k eep low weight and torque on bit. Unless an excessive amount of cement is left inside the casing, the cement could be drilled out using a stabilised string.

• 12.6.

With dual stage, run to the DV depth, drill out the collar, plug and bomb then perform a DV casing test at the previous casing test pressure.

SQUEEZING

1)

2)

3) 4) 5)

6)

7) 8) 9) 10)

Note:

Set a Cement Retainer (CR) using wireline whenever possible to 5 to 10m above the perforations. Correlate the CCL and GR to avoid setting the CR across a collar or perforations. Run the Setting Tool on drill pipe, apply 10 ton weight on the CR and try to circulate testing the CR and the rubber seals (‘O’ rings) by pressurising up on the annulus. Pickup the stinger and test the surface lines from cementing unit to cementing head at 5,000psi. 3 Displace the pipe with 2m of water cushion. Stab the stinger in and perform a feeding test, recording injection rates and relevant pressures. Do not exceed fracture pressure. Pick-up the stinger and mix and pump the slurry. The slurry design depends on the feeding test results. In front and after the slurry, pump a cushion of treated water or spacer. Displace the first water cushion until it reaches the end of the pipe, then stop pumping and rapidly stab the stinger in. With high density slurries, close the annular BOP with a low pressure before stabbing the stinger in. Monitor that a DP tool joint is not across the BOP annular rubber. Apply a moderate squeeze pressure taking into consideration the increased hydrostatic effect of the cement column. Gradually increase downhole pressure to 500-1,000psi above the pressure required to initiate the flow calculated with a residual cement column. If pressure increases by pumping, proceed until the maximum pressure of 500 psi below fracture pressure is reached. If no pressure increase is observed, adopt the ‘Hesitation Technique’, pumping small amounts of slurry (just enough to determine if the formation is feeding) and waiting a few minutes allowing for complete bleed-off. Record a residual pressure. Increase the pump pressure according to the increase in bleed off pressure, until the maximum squeezing pressure is reached. A high final squeeze pressure does not necessarily indicate a successful squeeze.

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11)

0

If the pressure reaches a high value, help the stinger seals by applying pressure on the annulus.

• 12.7.

154 OF 234

Pick-up the stinger and reverse circulate out the excess cement. Record the volume fluid taken back.

LINERS

12.7.1. Preliminary Preparations

1) 2)

3)

4) 5)

6)

7) 8) 9)

10)

A meeting shall be held with key personnel to discuss the detailed programme and operational procedure. Is recommended to make up the liner hanger system already assembly and test at the Contractor's workshop including: running tool, pup joints, plug holder bushing, packer extension, etc., checked, drifted and measured. Under normal conditions, the liner will be hung with a 100 to 150m overlap into the previous casing. If a smaller overlap is necessary due to a particular situation, it shall never be less than 50m . If the rat hole exceeds the overlap length, set a cement plug at a distance from the liner shoe setting depth shorter than the overlap itself. Strap the drill pipe as it is pulled out of the hole on the last trip before running the liner. Separate the DC, BHA and extra DP stands in the derrick according to the calculated running string for easy checking and operation. Drift the drill pipe and check the ID of all tools, subs, crossovers, pup joints of the running string to ensure passage of the drill pipe pump down plug and for dropping ball for hydraulic liner hanger. Visually inspect all tools and equipment for damaged components, dents etc. Record the shear pressure of all shear pins. The liner hanger OD and packer extension sleeve shall be checked and the length measured. The liner cementing plug system (single or dual plugs) should have 1,500-2,000psi shearing pressure to check the latch-in and verify exact displacement volume (pumps volumetric efficiency knowledge which is important to have a correct final bump plug). With a liner hanger assembly with a double plug cementing system, ensure the appropriate cementing head with dual drill pipe darts is used.

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0

12.7.2. Running And Setting

1) 2) 3)

Run the liner with the following operational procedure: Check that the liner hanger slips operate properly and are undamaged prior to running in the hole (mechanical type). According to the liner hanger design being used, check the proper distance between setting tool stinger and casing plug receptacle for the correct latch-in plugs.

4)

Perform a circulating test at the liner hanger top to assure sealing of the packing elements (‘O’ ring or ‘V’ chevron).

5)

Under no circumstance shall rotation be allowed to the running string ; use a back-up tong for connection make-up, and lock the rotary table (mechanical type).

6)

At every circulation point before hanger setting (previous casing shoe, open hole or bottom), keep circulating pressure at maximum of 80% of hanger slips setting value (hydraulic type). Record the exact liner and DP string weights including drag (hook load down and up) to calculate the exact neutral point for the setting tool release (10-15t bearing). When the liner setting depth is reached, start reciprocating slowly. Break circulation pumping very slowly (100-300lpm), then increase the flow rate to the desired value (observe for pressure surges to avoid formation fracture) and condition the mud as per the programme. Remove the kelly, drop the setting ball, install the cementing head with the swivel (drill pipe dart plug inserted) and indicating flag. Prepare the rig floor by-pass manifold with double lines and valves for direct and reverse circulations. After mud and hole conditioning, set the hanger following the procedures provided by the manufacturer. If circulation time is greater than 60min, set the hydraulic hanger before completing the circulation and with bottom's up above the liner head (minimum circulating volume before dropping setting ball is the DP plus casing capacity). Release the setting tool and pick up circa 3ft (1m) to ensure that it has released (never pull the stinger out of the packing or dogs above the packer's extension sleeve). For heavy liner or high angle wells, use a long stinger and packing (>3m) and packer extension sleeve (>6m).

7) 8)

9)

10)

11) 12)

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12.7.3. Cementing

1)

2)

3)

Cement the liner as per the Cementing Programme. Excess cement slurry will be 20 % of the caliper data volume, based on slurry return at the top of the liner. The slurry must be batch-mixed. Design a proper and compatible spacer to separate the drilling mud from the cement slurry (for 150m of annulus with balanced weight spacer possibly with 8-10 minutes contact's time). Displace the cement with the cementing unit on shallow liners. Use the rig pumps for deep liners.

4)

If no shear of wiper plug is observed, do not bump the plug. Use the theoretical displacement volume only.

5)

Reduce the pump rate to 300-400l/min, 1-2m before the expected bump plug. Once the theoretical volume has been displaced, if the plug does not bump, overdisplace a 2 maximum /3 of the shoe track volume (between the landing collar and the float shoe). Bump the plug with 500-1000psi above the final displacement pressure. However, the bumping plug value will be stated in the Drilling Programme.

6) 7) 8) 9)

3

Bleed off the pressure very slowly and check for back flow. Pressurise approx. 300psi in order to check the correct sting out. Pick up the setting tool and circulate at least twice the annulus capacity while moving the string. Pull the setting tool.

In case of liner hanger equipped with a CPH packer, the following procedure has to be followed: a)

Pressurise to approx. 300psi in order to check the correct sting out.

b)

Pick up the setting tool, with activating dogs above the extension sleeve head, and apply the appropriate weight to energise the CPH packer.

c)

Pick-up the setting tool above the extension sleeve and circulate at least twice the annulus capacity.

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13.

LOGGING

13.1.

LOGGING WHILE DRILLING (LWD) CONSIDERATIONS

0

Many factors must be considered to economically justify the use of LWD.

• • • • • • •

The majority of cost savings are due to a rig time reduction associated with wireline operations, Conventional slick-line directional surveys and setup charges (particularly for offshore wells). Improved rates of penetration (ROP) when better survey accuracy and real-time toolface data can be obtained Reduced risk of a lost well or BHA due to borehole instability High-profile exploratory wells where lwd is used for correlation, pressure detection, to pick casing points, identify potential pay intervals for early evaluation, or for insurance logging in the event that a wellbore may be lost. Highly deviated and horizontal wells where obtaining pipe-conveyed (tlc) or conventional wireline logs is extremely difficult or risky. In situations where alternatives to MWD are risky or do not exist, LWD should easily be justified when weighed against the potential risks of not using LW D

13.1.1. Advantages Of Using LWD

A neutron or density sensor in the BHA may help obtain the formation porosity and bulk density values before the formation washes out. A caliper on the LW D tool may also help to pinpoint formations where washout has occurred and log quality is compromised. Such a measurement can also be used to indicate borehole instability and help the driller adjust mud properties appropriately 13.1.2. Onshore Planning

Due to the peculiarity and complexity of MWD/LWD operations, a very high degree of collaboration is required between the Drilling & Completion Department specialist, Subsurface Geologist Department specialist and Service Company Representative, in the pre-job meeting for the operation to determine:

• • • • • •

The most suitable tools. Their positioning in the BHA The drilling parameters to be used If the stabilisers are correctly positioned in the BHA, according to the LWD tools The maximum admissible flow through the LWD tools must not be exceeded, otherwise substantial erosion damage will occur inside the tool. Limiting the solid content in the mud in order not to exceed the LWD tools limitations.

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13.1.3. Rig Planning

The driller’s depth measurement should be of the utmost accuracy as is possible. The ROP should allow the LWD data sampling as planned in the basis of the pre-job meeting, in order to reach the LW D objectives. It is important to highlight that the peculiarity and complexity of MWD/LWD operations require a very high degree of liaison and collaboration among the Subsurface geologist, Drilling & Completion supervisor and LWD Service Operator present at the wellsite during the operations (during the rig site pre-job meeting) to verify/confirm:

• • • • •

Tool positioning in the BHA The drilling parameters to be used Stabiliser positioning in the BHA is correct, according to the LW D tools The maximum admissible flow through the LWD tools must not be exceeded, otherwise substantial erosion damage will occur inside the tool. Limiting the solid content in the mud in order not to exceed the LWD tools limitations.

13.1.4. Contractor Advanced Knowledge

• • • • • • •

Drilling mud characteristics (if oil or water basis mud, mud salinity, presence of solids, etc..). Drilling section interval. ROP, deviation, type of BHA and bits. Occurrence of overpressured levels or fractured intervals The accurate measurement of the BHA length made by the drilling crew The accurate measurement of the distance from the rotary table to the sea floor on offshore rigs.

13.1.5. Rig Monitoring System Requirements

Radioactive sources must be used in LWD which are very similar to those used in wireline logging. Equipment for monitoring mud radioactivity must be used on all jobs requiring radioactive sources. 13.1.6. Shock Mechanisms That Can Cause Lwd Tool Failure:

• • • • • • • •

Bit bounce (particularly in vertical holes, with tricone bits and in hard rock environments); Torsional shocks and ‘stick-slip’ (commonly found in high angle wells and with aggressive PDC bits run with too much weight). Thinly bedded formation changes (bit and stabiliser in different lithologies) Reaming (sudden releases of energy) Drilling cement (unstabilised BHA in casing) Under-gauge bit (stabiliser digging) Stabilisers hanging on ledges or dog legs Buckling of the BHA (through incorrect application of weight on bit)

13.1.7. Solutions To Shock Problems:

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• • • • • • 13.2.

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Change the weight on bit (in some cases briefly stopping the r otation), Use downhole motors, Adjust the flow rate, Change the mud system/hydraulics, Adopt the use of shock subs, Add thrusters and roller reamers.

WIRELINE LOGGING

13.2.1. General Guidelines

1) 2) 3) 4) 5) 6)

7)

8)

9) 10)

11)

Prior to logging, the hole shall be circulated clean and the mud conditioned. After logging and prior to running casing, a wiper trip shall be carried out to condition the hole. If there is a long logging period or before a RFT, an intermediate wiper trip shall be run if deemed necessary by the Company Drilling and Completion Supervisor. During wireline operations, the mud level shall be continuously monitored with the trip tank, particularly, while pulling out logging tools. Extreme caution shall be taken when the tools are run or pulled through casing shoes, mudline suspension systems, wellheads, BOPs and rotary tables. The Company Well site Geologist is responsible for log quality. The Company Drilling and Completion Supervisor still retain overall responsibility particularly related to operating efficiency and safety and shall support the Company Well Site Geologist to ensure overall log quality. The Logging Engineer shall immediately inform the Company Drilling and Completion Supervisor of any obstacle or difficulty encountered while running or pulling out of the hole. When running the gas boomer for velocity surveys, ensure that an adequate amount of safety slings are used to prevent disengagement of the boomer from the crane wiggle weight. The weak point in the logging string shall be checked and changed regularly to avoid its premature breaking when running tools under normal hole conditions. The Company Drilling and Completion Supervisors must be sure the Logging Engineer has dimensional drawings of all tools run in hole, has appropriate overshot for all tools and appropriate crossovers are available on the rig floor for a possible fishing operation of logging tools. Under normal circumstances, all logging equipment transported to the rig site by helicopter, should be returned to shore by helicopter also. If logging equipment has to be returned by sea, the Eni-Agip shore base should dispatch the proper racking facilities and boxes to the rig. When logging equipment is shipped to the rig, there is no objection against a return trip by sea, since the equipment is prepared for such transport.

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13.2.2. Preparations

1)

2)

3) 4)

Reconfirm the Logging Programme with Company Office (Exploration and Reservoir Departments) and determine the details which may have been omitted from the initial programme, such as logging intervals, vertical scales, etc. Notify the Logging Contractor of the required logs, specifying special logging tools to be delivered when required. Also provide them with hole information such as high bottom hole temperature, high pressure, t ight hole, deviation records, etc. Check that the mud samples have been collected, properly labelled and given to the Logging Engineer for resistivity measurements. Extreme care shall be taken in collecting mud samples as well as measuring mud resistivity and temperature. Mud samples shall be taken from the mud outlet of the shale shaker immediately before stopping circulation and pulling drill pipe in preparation for logging. Mud samples obtained from the active pits are not representative of the mud in the well and are not a suitable substitute.

13.2.3. Quality Control

1)

2) 3)

4)

5)

6)

7)

All logging tools must be correctly calibrated before each logging run. To facilitate the calibration, the Logging Engineer will need a mud sample (Refer to previous point above). All logs should be run at the correct logging speed. Correlate the casing shoe depth and total depth by driller measurements versus electric line measurement. Consistent differences should be resolved and explained in the remarks of the log heading. Check that on every long run, three thermometers are used to record the bottom hole temperature and that they are changed after every two successive runs. Also record the time of the end of the last circulation and the time when thermometers in the logging tools have reached TD. Mechanical and electrical zeros, repeat section, overlaps sections and special checks should be printed on the final copies of the logs. Overlap sections should be run over any anomalous reading. Field reports should be prepared during logging operations. On second and subsequent runs, overlap the last 150ft (45m) of the log as a logger overlap may occasionally be required for interpretation purposes. Overlap sections and final prints of the logs should be reproduced in the field. Request the Logging Engineer to include any information of interest in the remarks in the log headings.

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13.2.4. Handling Explosives

1) 2) 3)

4) 5)

6) 7) 8)

9)

10)

The Company Drilling and Completion Supervisor is the person in overall charge throughout all perforating operations. The Logging Engineer is responsible for the storage, transport, handling, loading, arming and firing of perforating guns. Utmost care shall be taken during transportation, loading and back-loading of explosives, (explosives and detonators shall always be transported and stored in separate containers.) Local legislation may dictate storage and transporting procedures. The quantity of explosives stored must be kept to a minimum. Explosives shall be kept on the rig for the minimum time required for operations and during such time they shall be stored in a designated locked container. The handling of the explosives must be carried out only by authorised personnel. Explosives should never be stored in vicinity of hazardous materials, e.g. flammable or combustible liquids, compressed gases and welding equipment. The wellhead, derrick and logging unit must be electrically grounded together. A precise record must be kept of all explosives received, stowed or off loaded. Only authorised personnel shall handle explosives. When handling explosives, everybody not directly involved in the operation shall stay away from the area, while those involved shall stay out of the line of fire of the charges. The area should be marked off with barrier tape. As an electrical potential could trigger the detonators, any source of such potential shall be switched off to avoid premature detonation. Such sources include any radio transmitter (include crane radius) and welding equipment. The Company Drilling and Completion Supervisor shall collect all portable radios inside the Company Office in order to avoid any possibility of untimely use. Radio silence conditions shall be observed while guns are being primed and while primed guns are above sea bed. Off shore the following services shall be advised prior to radio silence being in force:

• • • • 11)

12)

13)

Stand-by vessel Helicopter operations Eni-Agip shore base Other nearby installations.

The Logging Engineer shall check that no other spurious potentials are present between the derrick, well-head and logging unit. In the event of uncontrollable sources of potential such as thunderstorms, operations involving the use of explosive shall be suspended. The only exception to the precaution mentioned above is the SAFE (Slapper Activated Firing Equipment) which can be operated, under any weather condition, during radio transmissions and welding operations. An emergency plan shall be prepared in case of fire on the rig.

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13.2.5. Handling Radioactive Sources

The radioactive sources are in the form of pellets which are permanently encased in a metal shield (packing) even during logging. This shield decreases the energy and hence the range of emissions. When the source is not in use, it shall be kept in a second metal shield, which further reduces the energy and range of the emissions. 1)

2) 3)

4) 5) 6) 7) 8) 9)

10)

Offshore transportation is generally conducted by ship. When transported by ship, the source shall be secured in a shipping container so as to avoid damage to the packaging. The shipping container shall be properly marked with radiation warning signs. If transportation has to be effected by helicopter, the source shall be placed as decided by the local Civil Aviation Administration in order to make landings or take offs possible During transfers of shipping container from supply vessel to the rig and vice versa, special precautions shall be taken in order to prevent t he loss of the container. Whenever the radioactive source is not in use, it shall be stored in a locked shield container, welded to rig deck and clearly marked with standard radioactive warning signs on all visible sides. The container shall be stored far away from the crew’s quarters, regularly occupied work space or food stuff stowage. The handling of the explosives must be carried out only by authorised personnel. Radiation levels shall be monitored on a regular basis to ensure that the protective shields are not defective. A log must be kept of the results of this monitoring. Radioactive sources shall be kept on the rig only for the time strictly necessary for logging, unless the frequency of operations makes this impractical. A precise record must be kept of all radioactive material received, stowed or offloaded. During transfer of a source from the container to the tool, only logging personnel shall be present. The hole must be covered when a logging source on the rig floor is bring transferred between the tool and the shield. The logging engineer is responsible for this. If a radioactive tool has been lost in the hole and all the attempts to fish have proven unsuccessful, the tool must be insulated in the hole by an hydraulic seal and mechanical protection. The hydraulic seal consists of a cement plug set above the source of at least 500ft (150m) length in two separate operations and at least 50m (150ft) over the first permeable zone. The cement could be dyed with a red or purple color. The mechanical protection consists normally of a whipstock shoe or other deflection device above the cement plug. This gives protection from damage due to further attempts at drilling or deepening. During all future circulation’s the mud shall be carefully checked for radioactive contamination by the Logging Engineer using a Gamma-Ray tool immersed in the header tank of the shale shaker. However, local regulations will dictate the appropriate method of isolating the radioactive source. An emergency plan shall be prepared in case of fire on the rig.

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13.2.6. Logging Tool Fishing (overstripping method)

Logging tools may become stuck down the hole, for various reasons, such as:

• • • • •

Hole collapse or loose formation Hole bridge Torpedo or cable head caught in a key seat Cable or tool differentially stuck Tool caught in a split casing shoe.

The normal procedure to attempt to free a stuck tool is to pull tension on the wire up to just below the breaking strain of the weak point, or as advised by the Logging Engineer. Sometimes, pulling on the cable does not free the tool and on the contrary it may trap the tool further. When the wireline is still intact it is best to use a cable guide technique where the wireline will hold the fish in a centralised position and serve as a guide for the overshot. The following is the suggested procedure for the stripping-over (reverse cut and thread) technique: 1)

2)

3) 4)

5)

6) 7) 8)

9) 10) 11)

12)

A cable hanger is clamped on the cable and landed on the rotary table maintaining tensions of 1,000lbs over the cable weight. The cable is then cut 5 to 7ft (1.5 - 2m) above the hanger. A ‘spearhead’ rope socket is made up on the end of the cable remaining in the well. A rope socket, sinker bar and ‘spearhead’ overshot are made up on the end of the cable hanging in the derrick. Assemble the overshot on the rig floor and verify the connection between the spearhead and the overshot. Pick up and hang a stand of drill pipe over the rotary table. The spear head overshot is drawn up to the derrick man’s board and the derrick man lowers the cable with the spear overshot down the pipe. The spear head overshot is attached to the spear head, the cable is tensioned and the overshot is made up to the pipe. Spot weld the overshot guide to the bowl and make sure that at least two circulating ports are open. A little strain is taken on the cable and the cable hanger is removed. The drill pipe is then lowered through the rotary table and set on the slips. The ‘C’ plate is placed on top of the drill pipe tool joint in the rotary table to hold the section of cable in the well. The spear head overshot is released and pulled up to the derrick man so that he can send it down the next stand of pipe. The operation is repeated until the overshot is at a short distance from the fish. A circulating sub is made up on the top of the drill pipe. The lower section of the cable is landed on the circulating sub and t he spear head overshot is released. The kelly (or circulating head) is then installed and the mud is circulated to remove all the cuttings and debris in the overshot and from the top of the fish. Upon completion of the circulation the kelly is removed, the spear head overshot is connected to the spear head and a tension of approximately 2,000lbs (1t) is applied. The string is lowered and the overshot latched on to the fish. A tension increase when lowering the string after latching on to the fish, or a decrease when pulling up, is a good indication that the fish is engaged.

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If a ‘T’ sub and stuffing box are available on the rig, the string can be lowered while circulating. This will ensure that the overshot and the fish are clear from the cuttings and a pressure increase is another indication that the fish is engaged. 13)

14)

The cable hanger is then clamped clamped on the cable below the rope sockets and the hanger is set in the elevator. The weak point is broken by pulling on the cable with the travelling block. The cable is pulled pulled out of the drill drill pipe and the string is pulled out of the hole.

Note Note::

Whil While e runn runnin ing g in in the the over oversh shot ot with with DP, DP, a dec decre reas ase e in in cab cable le tens tensio ion n may may occur indicating that the tool has become free. In this case the tool is pulled until it latches inside the overshot. The procedure is then the same as stated above.

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14.

WELL ABANDONMENT

14.1.

TEMPORARY ABANDONMENT ABANDONMENT

14.1.1. During Drilling Operations

Any drilled well which is to be temporarily abandoned abandoned shall be cemented with Drilling Kill Weight mud below the plug. Where there is an open hole below the deepest string of casing a cement plug shall be placed in such manner that extends at least 50m above and below the casing shoe. The top of the cement plug shall be located and verified by mechanical loading. loading. If the condition of the formation makes cementing difficult, a bridge plug may be positioned in the lower part of the casing, but not more than 50m above the shoe and a cement plug at least 20m long shall be placed on t op of the mechanical plug. Then, a cement plug shall be set at least 50 - 100m in length into the casing, depending on casing diameter, between 20 - 50m below ground level or the seabed. The top of the cement plug shall be located and verified by mechanical loading. 14.1.2. During Production Operations

1)

Plugging programme before a production well test: Open Hole

In the part of borehole where casing has not been installed and where permeable zones containing liquid or gas have been found, cement plugs shall be placed in such a way as to prevent liquid or gas from cross flowing into other zones. For each individual zone the cement plug shall be positioned such that its upper and lower ends are located at least 50m above and below the zone respectively. respectively. The top of each cement plug shall be located and verified by mechanical loading. Deepest Casing Shoe

Where there is an open hole below the deepest string of casing, a cement plug shall be placed in such a manner that it extends at least 50m above and below the casing shoe. The top of the cement plug shall be located and verified by mechanical loading. loading. If the condition of the formation makes cementing difficult, a mechanical plug may be positioned in the lower lower part of the casing, but not more than 50m above the shoe and a cement plug at least 20m long shall be placed on top of the mechanical plug. These plugs shall be verified by mechanical loading or pressure tested for sufficient time and with enough differential pressure to detect a possible leak.

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Plugging programme after a production test: Uninteresting perforated zones

These intervals shall be isolated by means of a mechanical plug and shall be squeeze cemented. If the condition of the formation makes cementing difficult a cement plug 50m high will be set on top of the t he mechanical plug. If this is not possible, a cement plug shall be placed in such a way that the upper and lower ends of the plug are located at least 50m above and below the perforated zone respectively, or down to the nearest plug if the distance is less than 50m. All the plugs shall be described, as seen in the previous subsection. subsection. Interesting perforated zones

These intervals shall be isolated by means of a mechanical plug. Then, a cement plug shall be set at least 50 - 100m in length into the casing, depending on casing diameter, between 5 - 50m below the sea bottom. The top of the cement plug shall be located and verified by mechanical loading. 14.2.

PERMANENT ABANDONMENT

14.2.1. Plugging

A well has to be plugged so as to effectively eff ectively seal-off all potential hydrocarbon bearing zones from fresh water bearing formations and to protect any zones which may contain other minerals. 14.2.2. Plugging Programme Open Hole

All permeable zones in an open hole shall be plugged so that formation fluid is prevented from flowing from one zone to another. Plug(s) shall be set so that the top and the bottom is at least 50m above and below the zone(s). Each plug has to be tested as per the procedure in section 12.5. Deepest Casing Shoe

At the top of the open hole a cement plug shall be set so that the upper and lower ends of the plug are located at least 50m above and below the casing shoe. The plug shall be tested by mechanical loading. Perforated Casing Zones

Each zone tested through casing perforations shall be squeeze-cemented as soon as the test is finished, if the well is to be abandoned. A cement retainer will be set 10-15m above the perforated zone (avoid setting it on a casing collar) and an injection test shall be performed using fresh water and recording the pressure/flow rate ratios.

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The cement slurry volume will be calculated in order to have the cement from bottom perforation to the cement retainer and a minimum of 100ltrs slurry per metre of perforated zone into the formation. At the end of the squeeze, a 50m cement plug shall be set above the cement retainer. The length of this plug may be reduced to avoid any interference with upper intervals to be tested or produced. Liner Top

At the hanging point of the liner, a cement plug shall be set so that the top and bottom of the plug is at least 50m above and below the hanging point. The plug has to be tested as section 12.5. Intermediate Casing Shoe

In case any of the intermediate casings is not cemented up to at least 100m inside the previous casing shoe, the casing shall be cut at least 100m above the shoe of the previous casing string, the casing recovered, and a cement plug shall be placed so that it extends at least 50 - 100m above and below the casing cut point. Surface plug

A surface plug (at least 150m long) shall be set so that the top of the plug be 50m or less below ground level or seabed. After setting the surface plug, each surface casing and conductor pipe shall be cut at least 5m below sea bed, using mechanical cutters. 14.2.3. Plugging procedure

1)

2)

Cement plugs, set when abandoning abandoning wells, wells, should be formed from neat slurries slurries whenever possible. If static bottom hole temperature exceeds 110°C use special non degradable cements (i.e. Geotherm). Spacers should be pumped ahead and behind slurry. Special consideration should be given to the composition and volume of the spacers when the mud is oil based, calcium chloride or lignosulphonate lignosulphonate treated. The hydrostatic head reduction due to the spacer volume and density should be calculated. The spacers should have a volume corresponding to a length of at least 328ft (100m).

3)

4) 5) 6) 7)

The slurry slurry volume should be calculated using a calliper calliper log, if available. available. When a calliper log is not available, use a slurry volume excess based on local experience. Plugs exceeding 200m in length should not be set in one stage. If the hole is badly washed out or when when potential losses are expected, it is preferable to set two short plugs instead of one long one. All cement plugs shall be set using a tubing stinger. Displacement Displacement should should be be calculated calculated in order order to spot a balanced cement plug plug (hydrostatic heads inside the string and outside in the annulus shall be the same). An under displacement of 1 or 2bbl 2bbl is suggested suggested to help help draining draining the slurry slurry off the pipe when pulling out of hole.

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8)

9) 10) 11)

12)

14.3.

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As soon as the plug is set, pull out slowly 30 - 50m above the theoretical top of the plug and direct circulate (reverse circulation can also be considered if conditions allow it). Monitor and record spacer and slurry returns. Never stab the stinger back into the plug this is to avoid plugging of the stinger. The position and efficiency of all cement plugs shall be verified by locating the top of the plug and by applying bit weight on the plug after cement setting, usually 20,00040,000lbs, but dependent on hole size) . Records shall be kept of all plugs set and the results of tests shall be available for inspection.

CASING CUTTING/RETRIEVING

Consideration can be given, if deemed economically profitable, to cut and retrieve sections 5 of uncemented 7" and 9 /8" casing. Mechanical cutters are used for this operation. After cutting the casing, a complete circulation shall be made to reduce friction and balance the mud. If the casing is cut and recovered leaving a stub, one of the following methods shall be used to plug the casing stub: 14.3.1. Stub Termination (Inside A Casing String)

A stub inside a casing string shall be plugged by one of the following methods:

• •

A cement plug is set so as to extend 50m above and 50 below the stub, A permanent bridge plug set 10-15m above the stub and capped with at least 20m of cement.

14.3.2. Stub Termination (Below A Casing String)

If the stub is below the next larger string, plugging shall be accomplished in accordance with section 14.2.2 (Open Hole). The plug shall be mechanically tested. After setting a surface plug, each surface casing and conductor pipe shall be cut at least 5m below sea bed using mechanical cutters.

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15.

SURFACE WELLHEAD All the following information relates to the most common type of wellhead used by Eni-Agip in drilling activities (Refer to table 15.a through table 15.b).

15.1.1. PRELIMINARY CHECKS

1) 2)

Preliminary checks should be carried out when equipment is delivered to rig site. Identify all equipment by the part numbers stamped on each item. Check that the bolts are of the same length, diameter and part number as stated in the specification.

3)

Clean each part thoroughly, paying particular attention to:

• • • • • • 4) 5)

15.2.

Ring joints Ring joint grooves Packing seal seats Slips and slip seats Packing Threads of the lateral outlets (base flange).

Check the correct fitting of the slips and the support rings in the seats. Rubber parts shall be carefully identified and inspected upon arrival or upon removal from storage. Particular attention must be paid to looking for surface cracks and/or discoloration.

BASE FLANGE INSTALLATION

15.2.1. Welding Procedure

1) 2) 3) 4) 5)

6) 7) 8) 9)

10) 11)

Cut the 30” CP at cellar deck level (Jack-up) or at cellar bottom (land rig). Cut the 20” casing at about 50cm above the cellar deck or cellar bottom Empty the casing of mud bringing the fluid level down to 50 cm below the cellar deck or cellar bottom. Pre-heat the casing in the proximity of the final cut line up to the same temperature required for welding. Cut the casing at about 200-400mm from cellar deck or cellar bottom according to the o Drilling Programme, with a 30-35 internal bevel, using a guide frame to ensure the cut is horizontal. Thoroughly clean the surfaces to be welded and ensure they are free from paint, grease, rust or dirt. Install the base flange, checking it is horizontal and that the lateral outlets are aligned according to Company Drilling and Completion Supervisor’ s requirements. During welding operations ensure that all parts are protected against rain, wind, oil, mud or water. Heat the outside of the base flange and the inside of the casing with an oxyacetylene torch until the surface reach the required pre-heated temperature. For carbon steels, refer to Table, for chromium molybdenum steels refer to table 15.b. During this operation care shall be given to ensure the uniform expansion of the parts to be welded, as there may be significant differences in t heir wall thickness. Perform internal welding first. Start welding two sections of 5-10cm length diametrically

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0 0.

12)

13) 14) 15) 16) 17)

opposite. Continue and repeat this step at 90 Continue and repeat for subsequent sections until the first weld bead is completed. Subsequent passes should be performed continuously to complete the fill up the joint. Care should be given to avoid overlapping or causing any discontinuity of the weld bead during the same pass. The external weld should be performed using the same procedure. Once started, welding should be finished without interruption. Slow cooling should be carried out by using appropriate insulating systems. Pressure test the welding after complete cooling of the base flange. Check the base flange horizontal alignment and the inside alignment of the welded area. Seal the CP-casing annulus with two semicircular steel plates, leaving a test port for pressure checking.

% Carbon

Thickness (mm) 8

12

25

40 and more

0.2 C

20°C

50°C

100°C

150°C

0.3 C

50°C

70°C

150°C

200°C

0.4 C

100°C

200°C

250°C

300°C

0.5 C

200°C

300°C

300°C

300°C

0.6 C

300°C

350°C

350°C

350°C

0.7 C

300°C

400°C

400°C

400°C

Table 15.A - Required Pre-Heating Temperature Carbon Steels Chemical Analysis

Preheating

% Cr

% Mo

Temperature

0.5

0.5

100 - 150°C

1.0

0.5

100 - 150°C

2.0

0.5

150 - 200 °C

2.25

1.0

200 - 280°C

5.0

0.5

200 - 280°C

Table 15.B - Required Pre-Heating Temperature Chromium/Molybdenum Steel

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15.2.2. Safety

a)

During the time of operation to prepare and carry out the welding of the base flange, it is absolutely forbidden to work on the drilling f loor or in proximity of the wellhead.

b)

Make sure that the welder has efficient ground and safety switches conforming to CEI standards or other international/local regulations.

c)

The welder and his assistant must wear protective clothing.

d)

The welder must never be left by himself.

e)

The work area must be protected from any falling objects. For this reason a protective system with scaffolding must be built in order to guarantee safety during the base flange welding operations.

15.2.3. Pressure Testing

a)

A pressure test must be carried out using hydraulic oil after cooling of the base flange. Do not exceed 70% of API casing collapse pressure rating although the pressure values should be stated in the Drilling Programme.

b)

During this test, no sweating should occur. Upon completion of the test, install a wellhead protection cap to prevent objects accidentally falling into the wellbore.

c)

Re-install the /4” NPT plug in the test port.

3

15.2.4. Slips Installation

1) 2) 3) 4) 5) 6) 7) 8) 9)

All slips, packing elements and ring joints and their seats should be thoroughly cleaned and lubricated. Make sure the hinged slips and spring retaining rings are unlatched. Pick-up the BOP Be sure that the correct tension is applied to the casing string. Clean and inspect the ID of the base flange, polishing out any burrs or scratchers. Place two wooden boards of equal thickness across the base flange so that they straddle the casing. Wrap the casing slips around the casing. Latch the hinged slips and spring retaining ring. Lower the slips into the base flange bowl until they shoulder on the casing-spool, checking the correct alignment of the slip segments and the correct position. Slowly release the casing tension permitting the slips to set. Slippage between slips and casing must be prevented.

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15.2.5. Casing Preparation

1) 2) 3) 4) 5)

Cut a drain hole in the casing approximately 12” (30cm) from the top of the base flange. Allow the casing to drain and cut it off at 12” (30cm) above the base flange. Remove the casing reminant and prepare for the final cut. Remove the fluid inside the casing to below the top of the base flange using a cup or a bucket. 1 Cut the casing again at 4” (101.6mm) to 4 /4” (108mm) from the top of the base flange. Make sure the cut surface is level.

15.2.6. Primary And Secondary Packing Installation

1) 2) 3)

4)

Remove any burrs from the cut edges of the casing. Install the first primary support. Place the primary support over the casing with the bevelled side up. Lower the packing support until it shoulders on the body counterbore. Install the primary packing by: a) Clean and oil the casing and packing thoroughly. b)

Fit one side of the packing lip over the casing.

c)

Insert a clean welding rod (with the flux removed) or screw driver between the ID of the base flange and the OD of the packing. This will facilitate installation of the primary packing.

Tap around the packing with a hammer until the packing is completely installed on the casing.

Caution:

5)

Note:

6)

Note:

7)

Make sure that the packing is not cut or gouged during the installation.

Continue to tap the packing down until it is flush with the body flange and the outer lips have fully entered the bevel of the counterbore. Drive the packing down until it contacts the first primary support. If the body outlet valve is open, entrapped gas will not hinder seating of packing.

Install the second primary support by placing the upper packing support, with the lip receiving face down, over the casing and dropping it into place. When properly installed, the back face of the second primary support shall not protrude past the base flange face.

Install the first secondary support by placing the secondary support over the casing with bevelled side up. Lower the support until it rests on top of primary packing group.

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Install the secondary packing by: a)

Thoroughly grease the packing and fit one side of the packing lip over the casing.

b)

Install the packing with a hammer as in step (4).

c)

Drive the packing down until it contacts the first secondary support.

d)

Install the second secondary support by: placing the secondary support over the casing with bevel facing down. Lower support until it contacts the secondary packing.

15.2.7. Casing Spool Installation

1) 2) 3) 4) 5) 6)

7)

Clean the ring grooves on the bottom flange of casing spool and on the base flange, as well as the restricted packing bore of the casing spool. Oil the secondary packing and the restricted packing bore of the casing spool. Fill the void area with oil around the primary and secondary packing group. Place the metal ring joint in its groove. Align the bolt holes on the casing spool with the bolt holes on the base flange. Lower the casing spool over the secondary packing assembly (being careful not to roll or tear the secondary packing), until the casing spool comes to rest on the ring gasket. The use of a torque wrench is recommended. Assemble nuts to bolts and tighten. Wherever possible use a ‘hydraulic studs tensioning system’. This system allows tightening of all studs together at once with a reduced make-up time. Otherwise tighten them conventionally with the correct torque (Refer to 15.3) to ensure a proper seal, tighten the bolts using the following method:

8) Tighten the first bolt. 9) Tighten the bolt at 180° from the 1st bolt. 10) Tighten the bolt 90° from the 1st bolt. 11) Tighten the bolt 180° from the 3rd bolt. 12) Continue this alternating procedure until all bolts have been tightened. Checking the torque of the stud bolts must be done during drilling and after each BOP test due to the vibration and weight that they have to bear.

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RECOMMENDED FLANGE BOLT TORQUE

(API Specification 6A seventeenth edition 1996) It should be recognised that applied torque to a nut is only one of several ways to approximate the tension and stress in a fastener. The following table 15.c is for the convenience of the user only, and is based on calculations which assume certain friction coefficients for the friction between the studs and nuts, and between the nuts and the flange face. Two coefficients of friction are used in t he table:

•

0.13 approximates the friction with threads and nut bearing surface being bare metal well lubricated with API Bull 5A2 thread compound. 0.07 approximates threads and nut face coated with fluoropolymer material.

•

The table shows material properties equivalent to A193 grades B7 and B7M which are the most commonly used. Values of torque for materials having other strength levels may be obtained by multiplying the tabulated torque value by the ratio of the new material's yield strength to the tabulated material's yield strength. The following equations are used to calculate the values in table 15.d A S

π = [D − (0.9743P)]2 4

F

= σ A s

T

=

FE(P + πfES ) H + D + K  + Ff    2(E − PfS)  4 

where: A s D E F f H K

= = = = = = =

P

=

S T

= = =

σ

2

2

Stress area, ins or mm Thread major diameter, ins or mm Pitch diameter of thread, ins or mm Force per stud, lbf or Newton’s Friction coefficient Nut hex size = 1.5 D + 0.125ins (3.175mm) Nut internal chamfer = 0.125ins (3.175 mm) 1 Thread pitch = ins or mm Number of threadsper unitlength Secant of 30° = 1.1547 Torque, in/lbf 2 Stress in stud, lb/in

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Torque obtained for calculations and can be divided by 12 t o obtain ft/lbf. The stresses in these calculations are based on stress area and not thread root area. The following flanges should not be made up beyond 40,000 psi (275 MPa) bolt stress due to potentially high flange stress: Flange

Bolt Stress

5

2,000 psi (13.8 MPa)

3

2,000 psi (13.8 MPa)

1

2,000 psi (13.8 MPa)

5

3,000 psi (20.7 MPa)

13 /8 16 /4 21 /4 13 /8

Table 15.C - Flange Bolt Stress

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Stud with Sy = 80 Ksi



Bolt stress = 40 Ksi

Bolt stress = 52.5 Ksi

Bolt stress = 47.5 Ksi

Stud Diameter D

Thread per in

Tension

Torque

Torque

Tension

Torque

Torque

Tension

Torque

Torque

F

f = 0.07

f = 0.13

F

f = 0.07

f = 0.13

F

f = 0.07

f = 0.13

N

(in.)

(lbf)

(ft-lbf)

(ft-lbf)

(lbf)

(ft-lbf)

(ft-lbf)

(lbf)

(ft-lbf)

(ft-lbf)

(l/in.)

0.500

13

5676

27

45

7450

35

59

0.625

11

9040

52

88

11865

68

115

0.750

10

13378

90

153

17559

118

200

0.875

9

18469

143

243

24241

188

319

1.000

8

24230

213

361

31802

279

474

1.125

8

31618

305

523

41499

401

686

1.250

8

39988

421

726

52484

553

953

1.375

8

49340

563

976

64579

739

1281

1.500

8

59674

733

1278

78322

962

1677

1.625

8

70989

934

1635

93173

1226

2146

1.750

8

83286

1169

2054

109313

1534

2696

1.875

8

96565

1440

2539

126741

1890

3332

2.000

8

110825

1750

3094

145458

2297

4061

2.250

8

142292

2496

4436

186758

3276

5822

2.500

8

177685

3429

6118

233212

4500

8030

2.625

8

233.765

4716

8430

2.750

8

257694

5424

9712

3.000

8

309050

7047

12654

3.250

8

365070

8965

16136

3.750

8

491099

13782

24905

3.875

8

525521

15208

27506

4.000

8

561108

16730

30282

Table 15.D - Recommended Bolt Torque for API Flanges in ft/lbf for

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15.3.1. Slips Installation

1) 2) 3) 4) 5) 6) 7) 8) 9)

All slips, packing elements and ring joints and their seats should be thoroughly cleaned and lubricated. Make sure the hinged slips and spring retaining rings are unlatched. Pick-up the BOP. Be sure that the correct tension in the casing string is applied. Clean and inspect the ID of the casing spool, polish out any burrs or scratcher. Place two wooden boards of equal thickness across the casing spool so that they straddle the casing. Wrap the casing slips around the casing. Latch the hinged slips and spring retaining ring. Lower the slips into the casing spool bowl until they shoulder in the casing head checking the alignment of the slip segments for correct positioning. The casing tension shall be slowly released, permitting the slips to set. Slippage between slips and casing should not be allowed.

15.3.2. Casing Preparation

1) 2) 3) 4) 5) 6)

Cut a drain hole in the casing approximately 12” (30cm) from the top of the casing spool. Allow the casing to drain and cut it off at 12” (30cm) above the spool flange. Remove the casing remnant and prepare for the final cut. Remove the fluid inside of the casing to below the top of the casing spool using a cup or a bucket. 1 Cut the casing again at 5” (127mm) to 5 /2” (140mm) from the top of the casing spool. Make sure the cut surface is level.

15.3.3. Primary And Secondary Packing Installation

1) 2) 3)

4)

Remove any burrs from the cut edges of the casing. Install the first primary support by placing the primary support over the casing with bevelled side up. Lower the packing support until it shoulders in the body counterbore. Install the primary packing by: a) Thoroughly clean and oil the casing and packing. b)

Fit one side of the packing lip over the casing.

c)

Insert a clean welding rod (with the flux removed) or a screw driver between the ID of the casing spool and the OD of the packing. This will facilitate installation of the primary packing.

Tap around the packing with a hammer until the packing is completely installed on the casing.

Caution:

Make sure that the packing is not cut or gouged during the installation.

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IDENTIFICATION CODE



5)

If the body outlet valve is open, entrapped gas will not hinder seating of packing.

Install the second primary support by (refer to Section 15.2.6). Placing the upper packing support, with the lip receiving face down, over the casing and dropping it into place.

Note:

8) 9)

10) 11)

0

Continue to tap the packing down until it is flush with the body and after the outer lips have fully entered the bevel of the counterbore. Drive the packing down until it contacts the first primary support.

Note:

6) 7)

178 OF 234

When properly installed, the back face of the second primary support shall not protrude past the casing spool face.

Install the first secondary support by placing the secondary support over the casing with bevelled side up. Lower support until it rests on top of the primary packing group. Install the secondary packing by: a)

Thoroughly oil the packing and start one side of the packing lip over the casing.

b)

Install packing with hammer as in step (d).

c)

Drive the packing down until it contacts the first secondary support.

Install the second secondary support by(Refer to Section 15.2.6). Placing the secondary support over the casing with bevel facing down. Lower the support until it contacts the secondary packing.

15.3.4. Tubing Spool Installation

1) 2) 3) 4) 5) 6) 7) 8)

Clean the ring grooves on the bottom flange of tubing spool and on the casing spool, as well as the restricted packing bore of the tubing spool. Oil the secondary packing and the restricted packing bore of the tubing spool. Fill the void area with oil around the primary and secondary packing group. Install the metal ring gasket in the ring groove on the casing spool. Install the bolts in the bottom flange of the tubing spool. Align the bolt holes on the tubing spool with the bolt holes on the casing spool. Lower the tubing spool over the secondary packing assembly (being careful not to roll or tear the secondary packing), until the tubing spool comes to rest on t he ring gasket. Assemble nuts to bolts and tighten. wherever possible use a ‘hydraulic studs tensioning system’. This system allows tightening of all studs at once together with a reduced make-up time. Otherwise the flange stud bolts must be tightened conventionally with the correct torque (Refer to 15.3).To ensure a proper seal, tighten the bolts using the following method:

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0

a)

Tighten the first bolt.

b)

Tighten the bolt 180° from the 1 bolt.

c)


d)


e)

Continue this alternating procedure until all bolts have been tightened.

st

st

rd

15.3.5. Primary And Secondary Packing Group Test

To properly test the primary and secondary packing groups it is necessary to have the following components and fittings:

• • • • • • •

High pressure hydraulic test pump assembly complete with hose. 1 1 /2” needle valve, /2” NPT Pin. 1 Tee, /2” NPT XX Heavy Box x Box. 3 1 Bushing, /4” x /2” NPT Pin x Box 1 Reducing bushing attached to the pump hose end, /2” NPT Pin x Pin. 1 Nipple, /2” NPT XX Heavy x 10” long; Pressure relief needle valve.

After completion of the casing spool and packing assembly, proceed to testing the packing groups with hydraulic oil as follows: 1) 2) 3)

4)

5) 6)

3

3

1

Remove the /4 “ NPT plug from the test port and screw on the /4” x /2” NPT bushing. Leave the check valve on seat. Install the test equipment. The test pressure is given in the Drilling Programme. Take care not to exceed 70% of the casing collapse rating. All test pressures should be kept on for at least 15 mins. During the seal test the annulus space valve of the previous casing must be kept open with the 2” LP plug disassembled, as a leak in the primary packing group could put the annulus space under pressure. Upon completion of the test, bleed off all pressure and unscrew the relief needle valve so as to avoid it breaking during the BOP stack movement. Test the BOP with a cup tester. The needle valve must be replaced in its relative test port with the needle completely open. The annulus space valve of the previous casing must be also kept open.

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0

4

3

2

1

20" 13 3/8" 9 5/8" 7"

WP (psi) Section 1 Section 2 Section 3 Section 4 Section 5

3K (A) 470 620 472 -

3K (B) 470 620 472 -

5K (C) 470 625 472 -

5K (D) 470 690 670 581 -

10K (E) 470 690 660 700 -

10K (F) 510 850 700 700 --

Figure 15.A - Wellhead Dimensions (mm)

15K (G) 510 850 700 750

15K (H) 510 850 700 750

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0

BREDA

13"5/8 x 3K; 13 5/8" x 3K; 7"1/16 x 3K DESCRPTION

P/N BREDA

Q.tY

BIT PILOT 7".

42580-003

1

SECONDARY RINGS 7"

42573-066

2

SECONDARY PACKING 7"

42572-027

1

TUBING SPOOL 7 1/16" x 3K

60739-001

1

STUDS 1 3/8"*260 mm

39925-007

20

RING JOINT RX-57

49623-020

1

PRIMARY PACKING 7"

42572-009

1

PRIMARY RINGSI 7"

42573-017

2

SLIPS 7"

59215-066

1

CASING SPOOL FLANGE

VALVE 3000 Fl. 2 1/16" x 3K

2

NIPPLE. 2 1/16" API 1/2"NPT

1

COMPANION FLANGE . 2"1/16 Thr. 2 1/6" API

2

BULL PLUG 2"1/16 API

1

RING JOINT R-24

4

STUDS 7/8" x 8"

16

CASING SPOOL FLANGE

Csg 13 3/8" Csg 9 5/8" Csg 7"

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1

SECONDARY RINGS 9 5/8"

42573-041

2

SECONDARY PACKING 9 5/8"

42572-022

1

CASING SPOOL 13 5/8" x 3K

59203-001

1

STUDS 1 3/8"* x 260 mm

39925-007

20

RING JOINT RX- 57

49623-020

1

PRIMARY PACKING 9 5/8"

42572-023

1

PRIMARY RINGS 9 5/8"

42573-044

2

SLIPS 9 5/8"

59215-069

1

VALVE 3000 Fl.2 1/16" 5000

2

NIPPLE FIL. 2 1/16" x 1/2" NPT

1

COMPANION FLANGE 2"1/16 Trh. 2"1 /16 API

2

BULL PLUG 2"1/16

1

RING JOINT R-24

4

STUDS 7/8" x 8"

16

BRADEN HEAD FLANGE BRADEN HEAD 13 5/8" x 3000 psi

59215-001

1

VALVE 3000 Fl.2 1/16" x 5000

1

NIPPLE 2 1/16" API x 1/2" NPT

1

NIPPLE FIL. 2 1/16" API

1

COMPANION FLANGE. 2"1/16 Trh. Fil. 2"1/16 API

2

BULL PLUG 2" 1/16

1

RING JOINT R-24

2

STUDS 7/8" x 6"

16

Figure 15.B - Breda Wellhead Type ‘A’

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0

BREDA

13"5/8 x 3K; 13 5/8" x 3K; 9" x 3K DESCRPTION

P/N BREDA

Q.tY

BIT PILOT 7".

42580-005

1

SECONDARY RINGS 7"

42573-081

2


42572-042

1

TUBING SPOOL 13 5/8 - 9"" x 3K

60649-001

1

STUDS 1 3/8" x 260 mm

39925-007

20

RING JOINT RX-57

49623-020

1

PRIMARY PACKING 7"

42572-009

1

PRIMARY RINGSI 7"

42573-017

2

SLIPS 7"

59215-066

1

CASING SPOOL FLANGE

VALVE 3000 Fl. 2 1/16" x 3K

2

NIPPLE. 2 1/16" API 1/2" NPT

1


2


1

RING JOINT R-24

4

STUDS 7/8" x 6"

16

CASING SPOOL FLANGE

Csg 13 3/8" Csg 9 5/8" Csg 7"

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


42573-041

2


42572-022

1


59203-001

1

STUDS 1 3/8"* x 260 mm

39925-007

20

RING JOINT RX- 57

49623-020

1


42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1

VALVE 3000 Fl.2 1/16" 5000

2


1

COMPANION FLANGE 2"1/16 Trh. 2"1/ 16 API

2

BULL PLUG 2"1/16

1

RING JOINT R-24

4

STUDS 7/8" x 8"

16


59179-001

1

VALVE 3000 Fl.2 1/16" x 5000

1


1


1


2

BULL PLUG 2"1/16

1

RING JOINT R-24

2

STUDS 7/8" x 6"

16

Figure 15.C - Breda Wellhead Type ‘B’

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183 OF 234


0

BREDA

13"5/8 x 3K; 11" x 5K; 7 1/16" x 5K DESCRPTION

P/N BREDA

Q.tY

BIT PILOT 7".

42580-003

1

SECONDARY RINGS 7"

42573-066

2


42572-027

1

TUBING SPOOL 11" x 5K 7 1/16" x 5K

60410-001

1

STUDS 1 7/8" x 350 mm

39925-017

12

RING JOINT RX-54

49623-019

1

PRIMARY PACKING 7"

42572-021

1

PRIMARY RINGSI 7"

42573-062

2

SLIPS 7"

59215-046

1

CASING SPOOL FLANGE

VALVE 3000 Fl. 2 1/16" x 3K

2

NIPPLE. 2 1/16" API 1/2"NPT

1


2


1

RING JOINT R-24

4

STUDS 7/8" x 6"

16

CASING SPOOL FLANGE

Csg 13 3/8" Csg 9 5/8" Csg 7"

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


42573-041

2


42572-022

1

CASING SPOOL 13 5/8" x 3K; 11" x 5K

59714-001

1

STUDS 1 3/8"* x 260 mm

39925-007

20

RING JOINT RX- 57

49623-020

1


42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1

VALVE 3000 Fl.2 1/16" 5000

2


1

COMPANION FLANGE 2"1/16 Trh. 2"1/16 API

2

BULL PLUG 2"1/ 16

1

RING JOINT R-24

4

SPUDS 7/8" x 6"

16


59179-001

1

VALVE 3000 Fl.2 1/16" x 5000

1


1


1


2

BULL PLUG 2" 1/16

1

RING JOINT R-24

2

STUDS 7/8" x 6"

16

Figure 15.D - Breda Wellhead Type ‘C’

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184 OF 234


0

BREDA

20"3/4 x 3K; 13"5/8 x 5K; 11" x 5K; 7"1/16 x 5K Description

P/N

Q.tY

CASING SPOOL FLANGE BIT PILOT 7" x 5 3/4"

42580-003

1

SECONDARY RINGS 7"

42573-066

2


42572-027

1

CASING SPOOL 11" x 5K - 7 1/16" x 5K

60410-001

1

STUDS 1 7/8" x 350 mm

39925-017

12

RING JOINT RX-54

42623-019

1

PRIMARY PACKING 7"

42572-021

1

PRIMARY RINGS 7"

42573-062

2

SLIPS 7"

59215-046

1

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


47844-050

2


42572-051

1

CASING SPOOL 13 5/8" x 5K - 11" x 5K

61496-001

1

STUDS 1 5/8" x 320 mm

47641-004

16

RING JOINT BX-160

42555-060

1


42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1

CASING SPOLL FLANGE

CASING SPOOL FLANGE 1

BIT PILOT SECONDARY RINGS 13 3/8"

42573-059

2

SECONDARY PACKING 13/8"

42572-026

1

CASING SPOOL 20 3/4" x 3K - 13 5/8" x 5K

60965-001

1

STUDS 2" x 370 mm

47641-018

20

RING JOINT RX-74

49623-027

1


42572-025

1


42573-060

2

SLIPS 13 3/8"

59215-113

1

60496-001

1

BRADEN HEAD FLANGE BRADEN HEAD 20" 3/4 x 3000

ACCESSORIES Description

Csg 20" Csg 13 3/8" Csg 9 5/8"

Q.ty

VALVE 3000 Fl. 2 1/16" x 5000

1

COMPANION FLANGE 2"1/16 x 5K Thr . 2"1/16 API

8

RING JOINT R-24

14

NIPPLE FIL. 2 1/16" APII

1

VALVE 5000 Fl. 2 1/16" x 5000

6

BULL PLUG 2"1/16 "

4


4

STUDS 7/8" x 6"

64

Csg 7"

Figure 15.E - Breda Wellhead Type ‘D’

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IDENTIFICATION CODE


185 OF 234


0

BREDA


P/N

Q.tY


42580-003

1

SECONDARY RINGS 7"

42573-066

2


42572-027

1


60655-001

1

STUDS 1 3/4"*380 mm

47641-005

16

RING JOINT BX-158

42555-058

1

PRIMARY PACKING 7"

42572-021

1

PRIMARY RINGS 7"

42573-062

2

SLIPS 7"

59215-046

1

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


47844-050

2


42572-051

1


58501-001

1

STUDS 1 5/8" x 320 mm

47641-004

16

RING JOINT BX-160

42555-060

1


42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1

CASING SPOLL FLANGE


BIT PILOT SECONDARY RINGS 13 3/ 8"

42573-059

2


42572-026

1


60965-001

1

STUDS 2" x 370 mm

47641-018

20

RING JOINT RX-74

49623-027

1


42572-025

1


42573-060

2

SLIPS 13 3/8"

59215-113

1

60496-001

1



Csg 20" Csg 13 3/8" Csg 9 5/8" Csg 7"

Q.ty

VALVE 3000 Fl. 2 1/16" x 5000

1


4

RING JOINT R-24

6


1

VALVE 10000 Fl. 2 1/16" x 10000

4

BULL PLUG 2"1/16 "

2


2

STUDS 7/8" x 6"

32 2

VALVE 5000 FL 2 1/16" x 5000 NIPPLE FIL. 2 3/8" EU x 1/2"NPT

2

BULL PLUGS 2 3/8" EU

2

COMPANION FLANGE 2 1/16" x 10K Thr 2 3/8" E U

4

RING JOINT BX - 152

8

STUDS 3/4" x 5 1/4"

32

Figure 15.F - Breda Wellhead Type ‘E’

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IDENTIFICATION CODE


186 OF 234


0

BREDA


P/N

Q.tY


42580-003

1

SECONDARY RINGS 7"

42573-066

2


42572-027

1


60655-001

1

STUDS 1 3/4"*380 mm

47641-005

16

RING JOINT BX-158

42555-058

1

PRIMARY PACKING 7"

42572-021

1

PRIMARY RINGS 7"

42573-062

2

SLIPS 7"

59215-046

1

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


47844-050

2


42572-051

1


61505-001

1

STUDS 1 7/8" x 440 mm

47641-071

20

RING JOINT BX-159

42555-059

1


42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1


42573-059

2


42572-026

1


61117-001

1

STUDS 2" x 480 mm

47641-061

24

RING JOINT BX-165

42555-065

1


42572-025

1


42573-060

2

SLIPS 13 3/8"

59215-113

1

55990-001

1

CASING SPOLL FLANGE

CASING SPOOL FLANGE BIT PILOT

BRADEN HEAD FLANGE BRADEN HEAD 21"1/4 x 5000


Csg 20" Csg 13 3/8" Csg 9 5/8"

VALVE 5000 Fl. 2 1/16" x 500 0

1


2

RING JOINT R-24

2


1

VALVE 10000 Fl. 2 1/16" x 10000

6

BULL PLUG 2"1/16 "

1


1

STUDS 7/8" x 6"

Csg 7"

Q.ty

16

NIPPLE FIL. 2 3/8" EU x 1/2"NPT

3

BULL PLUGS 2 3/8" EU

3

COMPANION FLANGE 2 1/16" x 10K Thr 2 3/8" EU

6

RING JOINT BX - 152

12

STUDS 3/4" x 5 1/4"

48

Figure 15.G - Breda Wellhead Type ‘F’

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IDENTIFICATION CODE


187 OF 234


0

BREDA


P/N

Q.tY


42580-003

1

SECONDARY RINGS 7"

to be defined

2


to be defined

1


59893-001

1

STUDS 1 3/4"*380 mm

47641-005

16

RING JOINT BX-158

42555-058

1

PRIMARY PACKING 7"

42572-021

1

PRIMARY RINGS 7"

42573-062

2

SLIPS 7"

59215-046

1

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


47844-050

2


42572-051

1


64505-001

1

STUDS 1 7/8" x 440 mm

47641-004

16

RING JOINT BX-159

42555-059

1


42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1

CASING SPOLL FLANGE


BIT PILOT SECONDARY RINGS 13 3/8"

42573-059

2


42572-026

1


61117-001

1

STUDS 2" x 480 mm

47641-061

20

RING JOINT BX-165

49623-027

1


42572-025

1


42573-060

2

SLIPS 13 3/8"

59215-113

1

55990-001

1


ACCE SSOR IES Description

Csg 20" Csg 13 3/8" Csg 9 5/8" Csg 7"

Q.ty

VALVE 5000 Fl. 2 1/16" x 5000

1

COMPANION FLANGE 2"1/16 x 5K Thr . 2"1/16 A PI

2

RING JOINT R-24

2

NIPPLE 2 1/16" API

1

VALVE 10000 Fl. 2 1/16" x 10000

4

BULL PLUG 2"1/16 "

1


1

STUDS 7/8" x 6"

32 2

NIPPLE FIL. 2 3/8" EU x 1/2"NPT BULL PLUGS 2 3/8" EU

2

COMPANION FLANGE 2 1/16" x 10K Thr 2 3/8" EU

4

RING JOINT BX - 152

12

STUDS 3/4" x 5 1/4"

32

COMPANION FLANGE 2 1/16" x 15K WITH CO NNECTION BLIND COMPANION FLANGE 2 1/16" x 15K

1 1

VALVE 15000 FL 2 1 /16" x 15000

2

Figure 15.H - Breda Wellhead Type ‘G’

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0

BREDA

26 3/4" x 3K - 21 1/4" x 5K - 13 5/8" x 10K - 11" x 10K - 7 1/16" x 15K Description

TUBING SPOOL FLANGE 7 1/16" 15000

BIT PILOT 7" x 5 3/4"

42580-003

1

SECONDARY RINGS 7"

2

SECONDARY PAKING 7"

1 1

TUBING SPOOL 7 1/16" x 15K STUDS 1 3/4"*380 mm

47641-005

16

RING JOINT BX-158

42555-058

1 1

BX-158

PRIMARY PACKING 7"

11" 10000

PRIMARY RINGS 7"

42573-062

2

SLIPS 7"

49215-046

1

BIT PILOT 9 5/8" x 8 1/2"

42580-010

1


47844-050

2


42572-051

1

CASING SPOOL 11" x 10K

61505-001

1

STUDS 1 7/8"*440 mm

47641-071

20

RING JOINT BX-159

42555-059

1

PRIMARY PACKING 9 5 /8"

42572-023

1


42573-044

2

SLIPS 9 5/8"

59215-069

1

CASING SPOOL FLANGE

BX-159 13 5/8" 10000

BX-165

CASING SPOOL FLANGE

21 1/4" 5000

BIT PILOT 13 1/2" x 12 1/4"

1


2 1


BX-186


61117-001

1

STUDS 2" x 480 mm

47641-061

24

RING JOINT BX-165

42555-065

1


1


2

SLIPS 13 1/2"

1

26 3/4" 3000


BIT PILOT

Csg 24 1/2" Csg 18 5/8" Csg 13 1/2" Csg 9 5/8" Csg 7")


63526-030

2


63526-010

1


63551-001

1

STUDS 2" x 452 mm

24

RING JOINT BX-186

1


63526-001

1


63526-020

2

SLIPS 18 5/8"

63537-003

1

63519-001

1

BRADEN HEAD BRADEN HEAD 26"3/4 x 3K

Figure 15.I - Breda Wellhead Type ‘H’

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15.4.

189 OF 234

0

COMPACT WELLHEAD

Modern offshore drilling has uncovered a need for specially designed wellheads requiring less space with shorter installation times, thus offering a greater degree of safety. The solution to this need was met by the introduction of the unitised or compact wellhead which incorporates a casing flange, casing spools and possibly a tubing spool in a single offshore composite wellhead body. Eni-Agip uses the compact wellhead system in development drilling operations. The concept is quite different from that already described in section 15 and is similar to subsea wellhead systems from which the compact head was developed. Each manufacturer has its own particular product which differs from other manufacturers. Considering the number of different varieties available, it is not possible to provide a unique assembling procedure for all the existing unitised or compact wellhead types in this manual. figure 15.j and figure 15.k show a typical examples of compact systems. For specific running procedures reference should always be made to the well specific Drilling Programme and manufacturer's instructions. Technical advantages of the compact wellhead are:

• • • • •

Elimination of the rig time lost in nippling-up or down the BOPs, which is normally associated with conventional wellhead spools. Once the pack-off is set, the BOP can be tested. No crossover adapters are required. The stack-up height is greatly reduced by the elimination of the casing and tubing spools. 3 The Well is under BOP control from the time the 13 /8” BOP stack is installed on the Compact Wellhead to the time t he Xmas tree is installed.

A generic installation procedure for a typical compact wellhead is: 1) 2) 3) 4)

5)

6)

Cut all of the conductor pipe of the platform at the same level, in order to be able to use the same landing string throughout. Prior to running each casing size, run the appropriate hanger and landing string in order to measure and mark by painting the landing string, at the drill floor level. Prior to running the wellhead, remove all lateral studs (if present), avoiding any damage during the handling and running operations. If the compact wellhead system has some anchor screws to energise the pack off (e.g. the Breda type), remove the anchor screws after each cement job and visually check the hanger position. If the surface casing is cemented using plugs and not with an inner string, the running tool must be equipped with an extension sleeve (bore protector), covering the entire internal body and allowing the running of the plugs. If a bore protector is not available, consider the possibility of welding a wear bushing (or similar) below the running tool. Before running the casing, it is recommended to clean the hanger seat using an appropriate washing tool.

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7)

8)

190 OF 234

0

Always clean the inside inside of the wellhead after each cement job, opening opening all the ports ports and flushing with water. If the wellhead system utilises a pack off installed after the casing cementation, run an appropriate washing tool to clean the pack off seat immediately after the cement job. A compact emergency slip suspension system and emergency sealing assembly (with appropriate running procedures) must be available on the rig prior to starting operations. A back-up set of ‘O’ ring and sealing elements to re-dress all testing tools, running and retrieving tools, etc. must be available on the rig before operations start.

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0

Figure 15.J - Wellhead ‘Unitised 3,000 psi WP

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IDENTIFICATION CODE


192 OF 234


5

0

Figure 15.K - Wellhead SMS 13 /8 10,000 psi WP Assembly

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IDENTIFICATION CODE



15.5.

193 OF 234

0

MUDLINE SUSPENSION

The Mudline Suspension system is a method for supporting the weight of casing at the sea bed (mudline) while while drilling from a jack-up (Refer to figure 15.l and figure 15.l). It offers a method of disconnection for all casing strings, allowing the temporary abandonment abandonment of the t he well in the minimum of time and without having to cut the casings. The casing strings extend from the mudline back to the drilling unit. Conventional land type wellhead wellhead and BOPs are installed for well control during drilling operations. The system utilises simple fluted landing rings or expanding collets in which the hangers are landed. Each casing string is supported at the mudline by a mudline casing hanger. The running tools or the tieback tools connect the mudline casing hangers with the casing string above (landing string). Running tools used in the mudline system, include a square bottom thread, to install it into the hangers and seal, to maintain the pressure integrity of the running tool mudline hangers. The connection of the running tools is the casing thread as per the user’s requirement. Washout ports, located in the mudline hanger or in the running tool, ensure thorough flushing of the annulus. The Washout ports are exposed by a partial rotation of the running tool. When the washout ports are closed the pressure integrity of the casing is provided by the seals of the running tool. When temporarily abandoning a well, the casing landing string is retrieved by disconnecting the running tools. Corrosion caps used in temporary well abandonment may be installed at this time. Any, or all, of the casing strings can be re-installed back to a conventional conventional land type production tree, installed on a production platform wellhead deck, by means of tie-back tools. 3

Metal to metal seals between the tieback tool of 13 /8” or smaller mudline casing hangers provide a permanent pressure seal for the producing life of t he well. Eni-Agip have used a ‘mudline completion system’ enabling a well to be drilled using a Jackup drilling equipment and afterwards completing it with a subsea production system. Each mudline suspension manufacturer produces its own product different from those of competitors. Considering the great number of different features, it is not possible to provide a unique assembling procedure for all the existing mudline suspension system in this manual. For the installation procedure, refer to the Drilling Programme and manufacturer’s ‘operating procedures’.

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Figure 15.L - MLL Mudline Casing Suspension System

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Figure 15.M - The MLC Mudline Suspension System

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15.5.1. General Guidelines

1)

The Well programme will define the 30” casing string assembly including the type of connections, mudline landing ring space out and mudline landing ring final position. It is recommended to weld the 30” landing ring in such a way that its final position is at least 5m below the seabed with the squnch joint releasable connection at least 2m above the seabed (Refer to figure 15.n). A driveable Remote Releasable Connection may be installed on the landing joint which avoids sending divers to the sea floor to release the connector for abandonment (Refer to figure 15.o).

2) 3)

4)

5)

The 30” landing ring depth will be checked, after running the 30” CP, using a special 26” skirted bit. Ensure tools are adjusted to the ID of the mudline landing ring. Prior to the commencing the operation, ensure that all necessary equipment and tools required are onboard. Check part numbers, condition, dimensions, general compatibility with of the tools and equipment the casing and well requirements, tested and in good serviceable condition. A complete back up set of seals and ‘O’ rings and adequate casing pup joints, needed to space-out the running tools, must be available onboard. All running tools or tieback tools should be assembled to the respective hangers to confirm that there is no damage due to previous use or improper handling. Ensure all seals and ‘O’ rings are removed from the running/tieback tools before making them up. Running tools should then be removed and new seals fitted. The threads should then lubricated and protected by storing in the proper handling case. Before running the casing it is recommended that the mudline casing hanger and the running tool be made up to the casing joints or casing pup joint, and laid out on the pipe rack. Alternatively they may be joined together and racked back in the derrick. Before making up the running tool to the mudline casing hanger reconfirm that both seal and ‘O’ rings are intact and undamaged. Thread and seal areas should be greased following the manufacturer’s requirements (avoid the use of pipe or thread compound). Ensure that the hanger is correctly and fully made up to the running tool. Care must be taken in handling all equipment so that the rig tongs are not placed on any threaded area, seal area, collet or dog ring.

6)

7) 8)

9) 10)

The Casing landing string should be spaced with the wellhead to ensure that any coupling are be a min of 2m away from the casing hanging point. Casing pup joints, will be used if necessary. Prior to running the casing, make a wiper trip to TD, reaming any tight spots and cleaning out any hole fill. 5 When pulling out of the hole prior to running 9 /8” or smaller casing, pull the bit to the mudline suspension point and wash with the maximum flow rate possible at the casing hanger suspension point, to ensure that the landing or suspension profile is flushed. If available, the proper hanger landing profile clean-out tool should be used. This tool ensures the full cleaning of the landing profile. The correct casing torque must be applied to the casing landing string, as the string may have to be rotated in both directions during subsequent operations. Operation of mud line running, cementing, flushing through washing ports, mud line testing, well abandonment or tie back procedures must be strictly conducted as per manufacturer’s instructions.

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Ensure that there is no cement in the 30”-20” annulus above the running tool after the cement job, flushing the annulus through the mudline washing ports is essential. 3 In addition two tubing strings of 2 /8” OD should be run down to the 20” mudline hanger during the cement job to wash out the annulus in case the mudline washout ports have not opened. This system has a disadvantage of impeding the closure of the diverter, so precautions have to be adopted. It is recommended that five to ten barrels of flushing fluid are spotted in the hanger with cement retarder after washing, to help in avoiding early setting of any cement contamination.

12)

The washout ports are opened by rotation of the landing string. It is important to have the weight of the casing landing string in neutral, at the running tool. Close attention should be paid to casing string rotation, torque and vertical movement of the casing string, to ensure that the correct measurements are achieved and the operations are performed properly. At the end of the operation the washing ports of the running tool must be re-closed by the manufacturer’s procedures and torque figures. Do not over-torque especially if elastomer seals are used. If during the tightening up of the running tool there is any indication of casing backing out, disconnect the running tool and pull out the casing landing string to check all casing connections. Examine the running tool threads and inspect and replace all ‘O’rings/seals if necessary, prior to running back in the hole.

13) 14)

After tightening up of the running tool the integrity of the casing must be verified by pressure testing to the required pressure value as per the Well Programme. Measurement of the mud line position (hanger land-off point and top of casing hanger) must be recorded on the well report for landing subsequent casing strings and for future corrosion cap/tieback operations. The well report should specifically include full details of operation, number of turns, torque, etc. also for future installations of a corrosion cap/tieback operations.

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Figure 15.N - CP Mud Line Suspension

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Figure 15.O - Remote Realisable Connectors

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15.5.2. Temporary Abandonment Procedure.

It is assumed that the well has been plugged and secured and that wellhead and all surface equipment have been removed. The casing landing strings are recovered. Retrieve the last casing running tool and install the appropriate corrosion cap. Repeat the procedure in the same way for the outer casing. In this way the next largest casing will provide adequate guidance for the corrosion caps. Casing spears are used to apply torsion at the very top of each casing landing string for backing out the running tools. It is important to pick up the weight of the casing landing string, in order to place the running tool in neutral. Corrosion caps will be run with DP or HW using the appropriate J slot running tools. Check the RKB measurements for calculating the corrosion cap running string. Measurements must be recorded on the well report for future use when the well is to be re-entered. The well report should to include full details of the operations, number of turns, torque, etc. for future use in corrosion cap/tieback operations. Recovered mud line running tools must be careful cleaned and inspected to confirm that there is no damage. All ‘O’ rings /seals must be checked for cuts, age or heat cracks, loss of elasticity or change in hardness due to age or type of exposure. Damaged ‘O’ rings / seals must be replaced. Threads should then lubricated and protected by storing in the proper handling case for future use.

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16.

DRILLING PROBLEMS

16.1.

STUCK PIPE

The following is a list of the dif ferent types of pipe sticking which can occur due to:

• • • •

Differential sticking. Hole restriction. Caved in hole. Hole irregularities and/or change in BHA.

It is impossible to lay down hard rules which will successfully cover all cases. however, for each situation, indications about the possible causes of the problem, preventive measures and remedial actions are listed in the f ollowing subsections. Detailed procedure should be based on each particular case, evaluating every aspect of the problem and applying any past experience gained in the area concerned. 16.1.1. Differential Sticking Causes

This phenomenon can occur, where there is case of high differential pressure between the mud hydrostatic pressure and the formation pore pressure. Some indications of pipe becoming differentially stuck may be:

• • • •

The string becomes stuck in front of a porous formation. Pipe has not been moved for a period of time before getting stuck i.e. during a pipe connection. Circulation is free with no pressure variation. A normal amount of cuttings is observed at the shaker.

Preventive Measures

When conditions for a potential differential sticking are encountered, the risk can be minimised by applying the following procedure: 1) 2)

3) 4) 5) 6)

Reduce the mud weight as much as possible, maintaining the minimum differential pressure necessary for a safe trip margin. Reduce the contact surface by using spiral type drill collars also called NWS (No Wall Stick) and using a properly stabilised bottom hole assembly. A shorter BHA with a greater number of HWDP could be considered. Use mud with minimum solids content and low filtrate in order to obtain a thinner wall cake. Reduce the friction factor by adding lubricants to the mud. Keep the pipe moving and in rotation as much as possible. Consider the use of a drilling jar/bumper.

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Methods of Freeing Pipe

1) 2) 3) 4) 5)

Work the pipe applying cyclic slack-off and overpull combined with torque. Always check the reduction in the pipe yield stress due to the application of the torque. Spot oil-base mud, or oil containing a surfactant around the drill collars. Reduce the mud weight, if possible. Use a drilling jar/bumper. Conduct a DST procedure.

Note:

16.2.

Quick actions are fundamental in freeing the wall of stuck drill pipe, since the problem gets worse with time.

STICKING DUE TO HOLE RESTRICTION Causes

The most common causes of hole restriction:

• • •

Too thick a wall cake due to the use of high solids /high filtrate mud in front of porous and permeable formations. Swelling of formations containing clay. Extrusion of gumbo shale into the wellbore in underbalance situations.

Preventive Measures

Problems are usually suspected by increase in drag during connections. Once the cause is recognised to be any of the three previously listed, the following actions should be undertaken: 1) 2) 3)

Reduce mud filtrate, cake and solids content. Use inhibited mud. Increase mud weight.

4) 5)

Increase mud clearing capacity. Increase flow rate.

In all situations, frequent wiper trips can reduce the problem and provide information on the severity. Methods of Freeing Pipe

1) 2)

Work the pipe applying slack-off if the string has become stuck pulling out, and overpull if it stuck while running in. Spot a cushion to break and remove the mud cake around the drill collars.

3) 4)

Increase the mud weight, if possible. Use a drilling jar/bumper.

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STICKING DUE TO CAVING HOLE Causes

This problem is mainly experienced in shale sections. The most common causes are:

• • •

Hydration and swelling of clay minerals when in contact with fresh mud f iltrate. Insufficient supporting action of the mud hydrostatic column. Mechanical action of the drill string.

Preventive Measures

Depending on the various causes, there are different prevention possibilities, to reduce the severity of the problem and to avoid the consequences of sticking the string. Possible mud changes are:

• • • • • Note:

Reduce water losses. Lower pH value to 8.5 to 9 (if needed). Use inhibited mud. Add mud stabilising compounds (mainly sodium asphalt sulphonate). Increase the mud weight. It is not always drilling in underbalance which results in a caving hole.

• •

Increase the Y/PV ratio to create laminar flow on the wall after pipe. Increase the gel value to obtain a good cutting suspension when circulation is stopped.

Possible BHA changes are:

• •

Use bits without nozzles, particularly when reaming, t o avoid scouring the well. Use the minimum acceptable number of stabilisers.

Possible changes in parameters are:

• • • • •

Reduce rotary speed, if possible, to 80rpm or less. Reduce the mud flow rate to obtain laminar flow in the annulus between hole and drill collars. Avoid long circulation times across unstable sections. Do not rotate pipe when tripping. Use a spinner or chain out. Trip out with care to avoid swabbing. If any swabbing occurs, pull out with the kelly on.

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• • • • Note:

If circulation is possible, continue circulating trying to expel the caving. If the string becomes stuck across a carbonate formation, spot an acid pill. If circulation is blocked, try to regain it by applying pressure shocks and working the pipe at the same time. Special care is required to avoid breaking the formation i.e. overcoming fracture gradient below the stuck point. Use a drilling jar/bumper. The problem of pipe sticking due to cuttings dropping out is not necessarily related to a caving hole. The origin of such problems can also be an excessive rate of penetration in large holes and inadequate carrying capacity of the mud. In this case, change the mud properties, flow rate and if necessary, limit the rate of penetration.

It is good practice to spot high viscosity pills from time t o time to keep the hole clean. The methods of getting pipe free in this situation are the same as listed above. 16.3.1. Sticking Due To Hole Irregularities And/Or Change In BHA Causes

The causes for sticking, related to, hole conditions and change in BHA, are:

• • • • • •

Dog legs. Key seats. New bit is run following a dulled bit which was undersize. New stabilisers run to replace previous worn stabilisers. String is stiffer than the previous one. Rock bit run after a diamond or a core bit.

Preventive Measures

• • • • •

The formation of dog legs can be prevented by the use of packed bottom hole assemblies. Dog legs can be eliminated by using very stiff BHA's and reamers. A key seat can be eliminated by reaming it with a key seat wiper or an undergauge stabiliser installed on the top of the drill collars. Always ream a whole interval drilled with the previous bit. Always ream the cored section, even if a full gauge core bit was used.


1)

2) 3)

Work the pipe applying slack-off if dog leg or key seat (the string becomes stuck pulling out) and overpull if running a new BHA (the string becomes stuck while running in the hole). Spot an oil-based mud or oil containing a surfactant around the stuck point. If the stuck point is in a calcareous section, spot an acid pill.

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OIL PILLS

Depending on the specific gravity of the mud in the hole, two different types of oil pill can be used. 16.4.1. Light Oil Pills

To be used for mud specific gravity up to 1350g/l (11.3 PPG). 3

The standard pill will be obtained adding 10 to 30 l/m of surfactant to oil (diesel oil, crude oil or used engine oil). The procedure for the use of pill is t he following: 1) 2) 3) 4) 5) 6)

The pill volume shall be at at least least twice the volume volume of DC-open DC-open hole hole annulus (take into account excess for compensating hole enlargement). Pump at the maximum practical rate. In order order to have a pill pill volume volume in the annulus displace 1.3 times the volume volume of the DCopen hole. At 30 30 to 60 60 minutes intervals circulate out of the string batches, as a balanced plug. Work the string at the same time. Repeat the procedure procedure if the pill does not succeed succeed (the pill pill may be active for 4 to 16 hours).

16.4.2. Heavy Oil Pills

To be used for mud of a specific gravity greater than 1350g/l (11,3 PPG). For pill preparation clean a mud pit and mix (the ratios among the various components varies depending on the required density):

• • • • • •

Fresh water Calcium chloride Diesel oil (maximum 200l/minute) Emulsifier (maximum 1 sack/minute) to be added at the same time as t he diesel Viscosifier (heavy stirring for at least 15 minutes is required) Barite.

While mixing, continuous agitation is compulsory. The procedure for the use of the t he pill will be the following: following: 1) 2) 3) 4) 5) 6) 7)

Note Note::

The pill volume will be at least twice the volume between the drill collars and the open hole (take into account excess f or compensating hole enlargement). Pump a cushion cushion of diesel diesel oil oil with with 5% 5% Free Pipe, or similar, similar, ahead and behind of pill. pill. Pump at the maximum practical rate. In order order to have a pill pill volume in the annulus annulus displace 1.3 times times the volume of DC-open DC-open hole. At 2 to 3 hr intervals, circulate batches of 300 to 600l out of the string. Work the string at the same time. Repeat the procedure if the pill results are ineffective (the pill pill may be active for 20 to 48 hours). When When the the oil oil pill pill is circ circul ulat ated ed out out of of the the hole hole it shal shalll be be reco recov vered ered and and stored separately.

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Take Take into into acco accoun untt the the infl influe uenc nce e of of the the pill pill on the the hy hydros drosta tati tic c pre press ssur ure. e.

16.4.3. Acid Pills

The use of acid pills can be successful if the string gets stuck across of a carbonate formation. Considering the risks related to this operation, this should be carried out only if other methods prove to be ineffective.

• • • • •

Decisions concerning pill's characteristics (volume, compositions, strength, displacement schedule, etc.) shall be taken on a case by case situation, after consultation with the Company Drilling Off ice. Whichever recipe is adopted, consideration has to be given to the corrosion problem. The proper amount of corrosion inhibitor shall be used and the acid pill will be spaced with oil or water ahead and behind. Due to the acid reaction, gaseous products develop in the well, and special care is required when circulating out the pill. It may be necessary to circulate through the choke and line up the surface equipment to safely dispose of the gas. While displacing the acid in front of the formation, the gaseous product will cool off the drill string. To avoid breaking, do not work the string but only apply an overpull or slack off. As a result of the acid action, the permeability of the formation will increase, thus creating the conditions for possible mud losses.

Whenever acid is handled, the appropriate safety measures shall be adopted:

• • •

Wear gloves and protective clothing and have eyes protected with goggles. Ensure there are safety showers available for any personnel who come into contact with acid. Have water sprays ready to wash spilled acid. Ensure proper ventilation if the pill is mixed in a closed area.

16.4.4. Free Point Location

If it is confirmed that it is not possible to free the string by working the pipe, spotting oil or acid pills, the string shall be backed-off in order to allow proceeding with a different method such as running jars wash pipes, or abandon the hole and side-track. There are two methods for estimating the depth at which a string is stuck:

• •

Applying tension and measuring the pipe stretch. Locating the tow point with a free-point indicating tool.

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16.4.5. Measuring The Pipe Stretch

A reasonable estimate of the depth at which the pipe is stuck can be obtained by calculations using Hooke's Law. Applying two different tensile loads ( T 1 < T2) to the drilling string, two magnitudes of stretch (S1

< S2) are measured.

Calculating the differential stretch (E = S 2 - S1), differential pull (P = T 2 - T1) and applying Hooke’s Law, it is possible to determine the depth of free point (L) using the following formula. SI UNITS

L

=

26.374 x Wdp x E P

where:

L

=

735,294 x Wdp x E P

where:

L

=

Length free pipe in m

W dp

=

Plain end pipe weight in kg/m

E

=

Differential stretch in mm

P

API UNITS

=

Differential pull in kN

L

=

Length free pipe in ft

Wdp Wdp

=

Plain end pipe weight in in lb/ft

E

=

Differential stretch in ins

P

=

Differential pull in lbs

The value obtained is less reliable as deviation increases due to downhole downhole friction. Another minor inaccuracy is introduced by neglecting the changing cross section of the string at the tool joints. 16.4.6. Location By Free Point Indicating Tool

a)

A Free Point survey shall be run to select the back-off point.

b)

Free Point Indicators are essentially accurate strain gauges which measure molecular rearrangement between drag springs, setting dogs or electromagnets.

c)

The tool is run on a logging cable through which measurements of torque and stretch are sent to surface surf ace read-out instruments.

d)

The Free Point Indicator is lowered to various depths and, at each depth, tension and torque are applied to the string at the surface. The strain gauge indicates whether the pipe reacts at that depth to the applied tension and applied torque.

e)

The read-out of the instrument is given in percentage i.e. 100% 100% represents entirely free pipe.

f)

Pipe which appears to be free in tension does not always react to applied torque. There is a greater chance of succeeding with the back-off if the pipe is free under both tension and torque.

g)

Separate slim acoustic logs are designed to indicate intervals of stuck, stuck, partially partially stuck or free pipe, which may exist below below the upper stuck point.

h)

Interpretation of free point data is very subjective and susceptible to operator skill, hole condition, etc.

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16.4.7. Back-Off Procedure

Drill pipe or drill collars can be unscrewed downhole by exploding a charge inside a selected tool joint connection, close to the stuck point. Requisites for a successful back-off are t he following:

• • • • •

There must be sufficient minimum inside diameter. The charge must be accurately placed across the connection. There must be sufficient string shot strength (Refer to table 16.a). Neutral or slightly positive tension is applied at the back-off point. Sufficient left hand torque must be applied at the back off point.

As a general rule, t he first f irst attempt to back-off back-of f should be made at the first f irst connection above Free Point. If there is a failure, the second attempt should be performed on the first stand above the Free Point. Subsequent attempts should be made moving upward one stand at a time. To ensure a safe operation, the Company Drilling and Completion Supervisor shall carry out the following checks: a)

Ensure that tong and slips dies are clean, sharp and the proper size for the string above the rotary table.

b)

The tongs, snub and jerk lines are in working condition.

c)

The slip handles are tied together with strong line, to prevent prevent the slips being kicked out of the table when the pipe break out.

d)

The elevators elevators are latched around the pipe and loose under a tool tool joint joint with with the hook locked when torque is being applied to the string.

e)

Ensure that no no resilient torque remains in the string when it is picked up out out of the slips, unless the pipe is properly held with a back-up tong.

f)

A wireline cutter must be on the rig floor during the entire operation.

A detailed standard back-off back-off procedure cannot be used as there are too many variables. variables. The following is a typical generic procedure: 1) 2) 3) 4)

5) 6) 7)

Keep non-essential personnel off the rig floor. Install one or two Kelly Cocks on the pipe above rotary the table. If it is required due to hole hole conditions, install a stuffing box and pump in sub. Tighten up all string connections applying right hand hand torque (max. (max. 80% 80% of nominal nominal value). The torque should be worked down the string. This procedure should be repeated 4 to 5 times especially in crooked or deviated holes. Install the back-off tool in the string and run in the hole to around around 150-300ft (50-100m) below the rotary table. Pick up up the string to have have a hook hook load load equal equal to the weight, in air, air, of the pipe above the selected back-off point, plus 10 to 15%. Apply left hand hand torque torque in in a series of steps. Work the pipe at each each step step to transfer the torque downhole.

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8) 9) 10) 11) 12) 13)

16.5.

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The maximum amount of left hand torque should be 80% of the maximum value used for the right hand torque. Once the right amount of left hand torque is applied, run the Back-off tool to the Backoff point. Pull the drill string out of the hole. Fire the charge when across of the selected joint connection and retrieve the tool. Pull The string out of the hole. After the firing of the charge, if the connection has failed to back-off, continue to work the torque down the string before trying another string shot. If the operation is unsuccessful, release the left hand torque, circulate to clean the string from back-off debris and start again from step 4 and attempt a new back-off.

Note:

The Backing-off of drill collar connections should be performed by following the same procedure. Problems may arise due to the difficulty in identifying the Free Point and with higher left hand torque required.

Note:

In directional wells with high drift angles where it is difficult to transmit torque down to the stuck point, cutting techniques should be considered.

FISHING

16.5.1. Inventory Of Fishing Tools

The following tools shall be always available on the rig for the various hole sizes drilled:

• • • • • • • • • • • • •

Fishing jars to match the drill collars in use. Bumper subs to match the drill collars in use. Overshot and oversize guides with grapples, baskets and extension subs, to catch all diameters of tools in hole. Taper taps for drill pipe body and tool joints (this is a poor class of tool: overshots are preferable if available). Junk baskets or Globe-type baskets. Reverse circulation junk baskets. Junk subs. Fishing magnets. Milling tools. 1 Re-dressing tools for 5" and 3 /2" sheared DP. Impression blocks. Fishing tools to catch electrical log tools (supplied by electrical log contractor) and relevant crossover. Safety joints.

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16.5.2. Preparation

Before fishing operations begin, the f ollowing preparations shall be carried out: 1) 2) 3) 4) 5) 6)

Apply the greatest accuracy to all measurements. Draw a complete sketch of the equipment to be run, specifying lengths, inside and outside diameters and a description of each t ool. Make sure that the Contractor's personnel directly involved in operations are fully familiar with equipment to be used and have knowledge of limitations. The fishing equipment should arrive to the rig fully inspected. Further inspection and maintenance shall be carried out on the rig if in prolonged use. Keep mud properties in good conditions at all times. Keep rig equipment in good working conditions at all times.

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Depth From Surface in feet Pipe OD ins

0 to 3,000

3,000 to 6,000

6,000 to 9,000

9,000 to 12,000

Over 12,000

1

1

1

2

2

1

1

2

2

3

1

1

2

2

2

2

2

2

3

3

7

1

2

2-3

3-4

4-6

3 /2 to 4

2

3

3-4

4-6

5-8

2

3-4

4-6

5-9

6-12

3

4-5

5-7

6-10

7-14

2-4

2-5

3-7

3-8

4-9

2-4

3-6

4-8

4-10

5-12

3-6

4-8

5-10

6-12

7-15

4-6

5-9

6-12

7-15

8-18

6-12

8-12

8-15

8-18

3

2 /8 7

2 /8 1

Tubing

3 /2 1

4 to 4 /2 3

2 /8 to /8 1 1

Drillpipe

9

4 /2 to 6 /16 5

6 /8 1

3 /2 to 4 1

1

4 /8 to 5 /5 Drill Collar

3

5 /4 to 7 1

1

1

3

1

1

7 /4 to 8 /2 7 /4 to 9 /4

Casing

4 /2 to 5 /2

3

3

3

3

3

6 to 7

3

3

3

4

4

7 /8

5

4

4

4

4

5

5

7 /8

5

5

5

5

5

9 /8

5

5

5

5

6

6

3

6

6

6

7

7

10 /4

Table 16.A - Recommended Strands of 80gr/ft RDX Primacord for String-Shot

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16.5.3. Fishing Assembly

The standard fishing assembly consists of the following:

• • • • • • 16.6.

Fishing tool + Jar and Bumper Sub + Drill Collars + Heavy Weight Drill Pipe + Drill Pipe. Use as many drill collars as is in the fish. If the required number of drill collars is not available on the rig, use a jar accelerator. A Safety Joint should not be run. Since the Safety Joint will not transmit left hand torque, it would not be possible to back-off below it using a string shot. However, a Safety Joint could be run between the catching tool and the jar when a non releasing tool such as taper tap is being employed. Avoid any restrictions in the bore of tools run above the catching tool, which would prevent the use of a cutting tool or the back-off shot within the fish. Where losses are expected the use of a Circulation Sub in the fishing assembly should be considered.

FISHING PROCEDURES

16.6.1. Overshot

1)

Plan the operation taking into account the following factors:

• • • • • • 2) 3) 4) 5)

6)

7)

The catching action of the tool will stress the f ish neck in words. A regular, smooth shape of the f ish neck is necessary for a successful operation. Jarring is only possible only using type SFS, FS and XFS overshots. If the fish diameter is near the maximum catch or size, a spiral grapple is recommended. On the other hand, if the fish diameter is considerably below the maximum catch size, a basket grapple is preferable. If the hole is enlarged, use an oversize guide or run a bent drill pipe just above the overshot. When the fish has been milled over, if possible, run an overshot extension to avoid catching the fish by t he milled part.

Run the fishing assembly, space out as required, and make up the kelly. Lower the overshot to just above the fish and circulate for a few minutes to clean the top of the fish. Do not circulate excessively to as this may enlarge the hole. Prior to engaging the fish, record the weight of fishing string (up, down and rotating) with and without circulation. To engage a fish, the fishing string is lowered and rotated to the right very slowly, pumping at minimum rate. During the engaging operation, continuously monitor the weight indicator and stand pipe pressure. As the fish is engaged, allow the right hand torque to slack out and pull on the fish picking up rapidly the fishing string 5 to 8ft (2 to 3m). Drop the string 2 to 4ft (approximately 1m) and catch it in the brake to make sure that there is a firm grip. If possible, it should be considered to circulate bottoms up through the fish before pulling out of hole, particularly if potential reservoirs are exposed or penetration rates were high.

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When tripping out of the hole with the fish, the string must not be rotated, a chain or Kelly Spinner should be used. If pulling out of the hole wet, flow checks shall be carried out frequently.

16.6.2. Releasing Spear

1)

Plan this operation taking into account the following factors:

• • • • •

2)

The fish will be stressed outwards due to the catching action of the tool. A regular, smooth shape of the f ish is essential for a successful operation. To allow unlatching of the spear, if it is not possible to run an adequate number of drill collars above the releasing spear, the use of a bumper sub is recommended. Install a pack-off on the tool, if circulation is required after latching the f ish. Use the fishing jar If jarring is required. In this case the use of a Spear Stop is required. Check the Spear Stop OD when it is used in open hole and use the stop only if hole condition permits.

Perform the fishing job as per overshot procedure.

16.6.3. Taper Tap

1)

Plan this operation taking into account the following factors:

• • • •

2) 3) 4) 5)

The size of the taper tool should be selected in order to engage the fish with the middle of the tapered point. The taper taps do not allow free passage to the back-off tool. Excessive torque can damage the tapered thread and swell the top of the fish. It is nigh impossible to release the tool once engaged. For this reason its use has to be considered the last resort and only used after consultation with Eni-Agip Shore Base (Drilling Manager/Superintendent).

Run the fishing assembly, complete with safety joint, space out as required and make up the Kelly. Lower the catching tool to just above the fish and circulate a few minutes to clean the top of the fish. Do not circulate excessively as this may enlarge the hole. To engage the fish, apply right hand torque. A gradual increase of back torque is an indication of successful operation. Chain or spin the pipe out of hole with the fish.

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16.6.4. Junk Basket

1) 2)

This procedure is more successful in soft formations. A reverse circulation type junk basket is preferred to a forward circulation type.

3)

Use the following parameters:

• • • 4) 5) 6)

WOB = 2 to 4t Rotary = 45rpms 1 Low Pump Rate ( /2 pump rate while drilling).

Core approximately 20cm. Pick up to allow the junk on the side of the basket to fall into the pilot hole, then proceed coring a further +/-50cm. Pull the junk basket out of the hole After use, careful inspection and refurbishment is necessary.

16.6.5. Fishing Magnet

Magnets can be successfully used but only in hard formations to retrieve small steel objects such as bit cones, bearings, slips, tong pins and milling cuttings. To avoid sticking the fish in the hole, weight must not be applied. Fishing magnets may be run on wireline or on pipe. Wireline operations have the advantage of speed and economy. Pipe operations has the great advantage of utilising the circulation holes in the magnet to remove settling above the fish. 16.7.

MILLING PROCEDURE

There is a wide variety of mills specifically designed for various applications. Mills are available in two basic categories: ‘hydraulically activated mills’ and ‘fixed milling tools’. A Section Mill is a hydraulically actuated tool and is used to mill out a complete section of casing. Downhole section milling of casing, is generally done for the following reasons:

• •

To mill a section of casing that permits side-tracking in any direction. To mill the perforated zone in a production casing string or to expose cased off formations. The formations may be then underreamed and gravel packed past the original completion.

The most commonly used Fixed Mills are: Junk Mills

Used to mill all type of junk, including rock bit cones, reamers cutters, items dropped through the rotary, drill pipe cemented inside and outside, etc.

Pilot Mills

Designed to mill drill pipe, casing, tubing, wash pipe, safety joint, swaged casing, etc.

Taper Mills

Generally used to eliminate restrictions or to mill through collapsed casing.

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Washover Shoes

Designed to mill away formation or tool obstructions such as stabiliser blades, reamer cutters, expanded packers and bit bodies which may be holding the drill or tubing string in the hole

Special Mills (Window mills, Watermelon mills, etc.)

For casing side-tracking systems.

The following are general guidelines for the use of milling tools: a)

Milled cuttings are much heavier than drilling cuttings. Therefore, mud viscosity should be increased or high viscosity pills should be pumped to help in carrying the steel cuttings out of the hole.

b)

Oil based mud has poor carrying capabilities and should be avoided whenever possible. Polymer muds are most suitable for milling.

c)

Never mill faster than it is possible to remove the cuttings.

d)

Magnets placed in the flow line will help in removing metal particles from drilling mud. Removal of mill cuttings and debris reduces the wear on mud pumps and other equipment.

e)

A junk sub placed in the string above the mill can aid in catching the larger cuttings.

f)

Whenever possible, a stabiliser should be run within 60 or 90ft (20-30m) above the mill to prevent it from moving eccentrically.

g)

The stabiliser OD should not exceed the dressed OD of the mill.

h)

Always start rotating, with low rpm about 3ft (1m) above the fish. Lower onto the fish and adjust the weight and the rotary speed to obtain satisfactory penetration.

i)

Generally the most efficient milling rates are obtained by running the rotary at 80 to 100rpm. Milling with washover shoes is an exception and are usually more efficient at speeds of 60 to 80rpm. Continuously monitor the torque indicator during milling operations.

j)

‘Reading the cuttings’ is essential to evaluate the performance of the mill. The 1 1 ideal cuttings are usually /32" to /16" thick and 1" to 2" long. If cuttings are thin long stringers, penetration rates are probably too low and weight on the mill should be increased. If fish-scale type cuttings are being returned, penetration rate will improve by decreasing weight and increasing rpm.

k)

The type and stability of the fish (cemented or not) together with the hardness of the fish and/or cement are factors that affect milling rates.

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16.8.

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0

JARRING PROCEDURE

1) 2)

3) 4) 5)

6)

7)

Note:

Jarring should be done with a Kelly or Top Drive. If the use of a Kelly is not possible, secure the elevator latch by using a piece of rope or chain. Prior to jarring check the drill line sensor. Ensure the weight indicator readings are accurate and that the Dead Line Anchor is secure and free of debris. Check the derrick and all equipment for any loose items. When jarring, the drill floor must be cleared of all non-essential personnel. Prior to jarring, mark the drill string at the rotary table. Check the drill line usage, slip and cut if necessary. When sustained jarring is carried out, the drill line should be slipped at regular intervals, depending on the particular situation. Also check the derrick, lifting equipment and travelling block attachment bolts. Always allow the jars to trip within their safe working load. Wait until the jars have tripped before pulling the string further. Never exceed the safe working limit without confirmation that the jars have tripped. If a top drive system is used, after jarring, check the TDS as per the maintenance and operating specification. For details on jarring procedures, refer to ‘Drilling Jar Acceptance And Utilisation Procedures’ (STAP-M-1-M-5003).

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217 OF 234


17.

LOST CIRCULATION When lost circulation is encountered, some specific information regarding the situation is required prior to initiating corrective procedures. First, it is necessary to determine the magnitude of the losses. These may vary from minor seepage losses to partial and complete loss of returns. Second, the condition at the time of losses may proved an indication of the reasons for the lost of circulation. Losses during tripping are usually due to running pipe too quickly. During drilling, a change in drilling rate or change in Ethnology from cuttings indicates either a weaker, porous formation or a fault had been encountered. Mud weight and viscosity have also have increased. Third, it is necessary to locate the zone where the losses are occurring. If the losses are not on the bottom, at the casing shoe or at the last previous zone (if any), a temperature survey or gamma ray log may be run to accurately locate the zone.

17.1.

LOSS PREVENTIVE MEASURES

The depths where losses can be expected for each particular well, are usually predicted in the Drilling Programme, if enough information is available. If thief zones are likely to be encountered, the following procedure should be adopted: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10)

Keep the mud weight as low as possible but still providing an adequate overbalance. Control the ROP to prevent overloading the annulus with cuttings which could result in increased mud densities and/or constrict the annulus. Maintain a low yield point and gel strength of mud. Avoid excessive circulation rates. Run the pipe slowly to minimise pressure surges. Break circulation by first rotating away and reciprocating the pipe, then starting the pump slowly. Avoid pump surge. Do not use diamond bits. 14 Use bit nozzles larger than /32" ID. Have an adequate stock of LCM on the rig.

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17.1.1. REMEDIAL ACTION (WHILE DRILLING)

As soon as any irregularity is observed in the mud returns, the following procedure should be conducted: 1) 2)

3) 4)

Check the surface equipment for leaks. Run a subsea TV or ROV down the length of the marine riser, flex joint and BOP stack on both sides. When there is doubt or visibility is poor, close the BOP rams and check if the level still drops when the hole is isolated from the riser system. If still losing mud, stop pumping and observe the well. If the level remains static, the mud weight or viscosity may need to be reduced slightly and/or slight treatment with lost circulation material if required. If the level drops, the well must be kept full with mud or water, depending on the severity of the losses. An estimate can be made of the maximum weight the formation can withstand, measuring the volume of water required and calculating the new mud gradient. Circulation may be restarted by any or combination of the following means:

• • • • • • • •

Reduce flow rate (if possible). Reduce mud weight (if possible). Add LCM to the mud (the shale shaker must be by-passed). Wait for the formation to "heal". Spot a plug of thick mud and LCM at the thief zone. Spot a plug of dehydratable material containing LCM into the mud losses zone. Squeeze diesel oil bentonite (DOB) or diesel oil bentonite cement (DOBC) pills. Plug the thief zone with a gelled slurry.

The choice of the various possibilities listed above shall be submitted for evaluation of the well conditions on a case by case situation.(Refer to trouble shooting guides Mud Manual STAP l N 6051 Lost Circulation) 17.2.

USE OF DOB AND DOBC PILLS

1) 2) 3)

4) 5) Note:

If the tripping is considered safe (i.e. the hole stands full of mud), run open ended drill pipe to 10 to 30m above the thief zone. Pump the pill and displace it with mud to the bottom of the string. Close the BOP and squeeze pump down the annulus and the pipe at the same time. The flow rate shall be the same in both the annulus and in the drill pipe if DOB pills are being used. In case of DOBC pills, the flow rate in the annulus shall be half the flow rate in the drill pipe being used 2 Beware of fracturing the formation, do not exceed 500psi (35 kg/cm ). Open the BOP and pull out of hole. Do not reverse out. During this operation, reciprocate the string from time to time. If drag occurs, pull out the string is free before proceeding with a squeeze. Flush the mixing tank, cementing unit and lines with diesel oil in order to remove the presence of any water before mixing and pumping DOB or DOBC pills.

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REMEDIAL ACTION (WHILE TRIPPING)

As soon as any irregularity is noticed in filling the hole, the following general procedure should be carried out: 1) 2)

3)

4) 5)

17.4.

Check the trip tank system for leakage. Run a subsea TV or ROV down the length of the marine riser, flex joint and BOP stack on both sides. When there is doubt or visibility is poor, close the BOP rams and check if the level still drops when the hole is isolated from the riser system. If there is still mud losses, the cause of the lost circulation may be pressure surges due to running in the pipe too fast or the bit/stabilisers have balled up. Stop tripping and circulate the well. If full returns are observed, trip to bottom. If full returns are not established, the well must be kept full with mud or water, depending on the severity of the losses. Circulation may be restarted by one of the methods listed previously.

USE OF LCM PILLS

1) 2) 3) 4)

If tripping is considered safe (i.e. the hole stands full of mud), run open ended drill pipe to immediately above the thief zone. 3 Pump the LCM pill and displace half of it in the hole (minimum pill volume: 10m for a 1 3 1 8 /2" hole; 20m for a 12 /4" hole) and pull the pipe above the pill. Continue pumping the rest of the pill using the ‘Hesitation’ Technique and visually check the fluid level all the time. Repeat the procedure, if the previous was unsuccessful, change the type of LCM, if necessary.

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220 OF 234


Appendix A - Report Forms A.1

Initial Activity Report (ARPO 01)

INITIAL ACTIVITY

WELL NAME FIELD NAME

District/Affiliate Company DATE:

ARPO 01

Permit/Concession N°

Well Code

General Data

On shore

Cost center

Depth Above S.L .

Off shore

Joint venture

Ground Level[m]

AGIP:

Latitude:

Water Depth [m]

Longitude

Rotary Table Elev.[m]

Reference

First Flange[m]

Rig Name

Top housing [m]

Contractor

Ref. Rig RKB - 1st Flange

Rig Heading [°]

%

%

%

Program TD (Measured)

[m]

Program TD (Vertical)

[m]

Cellar Pit

Offset FROM the proposed location

%

%

Type of Operation

Reference Rig

Rig Type

%

Rig Pump

Depth [m]

Manufacturer

Distance [m]

Length [m]

Type

Direction [°]

Width [m]:

Liner avaible [in] Major Contractors

Type of Service

Company

Contract N°

Type of Service

Company

Contract N°

Mud Logging D. & C. Fluids Cementation Waste treatment Operating Time Moving

Jack-up leg Penetration

Supply Vessel for Positioning

[gg:hh]

Leg

Air gap

Penetration

Positioning

[hh:min]

N°

[m]

[m]

Anchorage

[hh:min]

Rig-up

[hh:min]

Delay

[hh:min]

Lost-time Accidents

[hh:min]

N°

Name

Horse Power

Bollard pull [t]

Rig Anchorage Anchor Bow N°

Angle

Mooring Line Weight

Type & Manufacturer

[t]

Piggy Back

Length Cable

Chain

[m]

[m]

Weight N°

[t]

Mooring Line Chain

Cable

Length

Ø

Length

Ø

[m]

[mm]

[m]

[mm]

Tension Operative

Total

[Tested]

Tension

Time

[t]

[t]

1 2 3 4 5 6 7 8 9 10 11 12 Note:

Supervisor

Superintendent

[hh:min]

ARPO

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IDENTIFICATION CODE



A.2

221 OF 234

0

Daily Report (ARPO 02)

DAILY REPORT

WELL NAME

Drilling

FIELD NAME

District/Affiliate Company

ARPO 02

DATE:

Cost center

Rig Name

RT Elevation

[m]

Type of Rig

Ground Lelel / Water Depth

[m]

Contractor

RT - 1 flange / Top Housing

st

La st c as in g

of

M.D. (24:00)

[m]

T.V.D. (24:00)

[m]

Top [m]

Diverter

Total Drilled

[m]

Bottom [m]

Annular

Rotating Hrs

[hh:mm] [m / h]

Ø nom.[in]

Top of Cmt [m]

Type

Report N° Permit / Concession N°

Stack

Well

N ex t C as in g

[m]

Well Code

BOP

Ø

w.p. [psi]

Annular

R.O.P.

Last Survey [°]

at m

Upper Rams

Progressive Rot. hrs

[hh:mm]

LOT - IFT [kg/l]

at m

Middle Rams

Back reaming Hrs

[hh:mm]

Middle Rams

Reduce Pump Strockes Pressure 1

Pump N°

2

3

Personnel

Middle Rams

Injured

Agip

Agip

Liner [in]

Lower Rams

Rig

Rig

Strokes Press. [psi]

Last Test

Others Total

Other Total

Lithology Shows From (hr)

To (hr) Op. Code OPERATION DESCRIPTION

Operation at 07:00 Mud type

Bit

Density Viscosity P.V. Y.P.

[kg/l] [s/l] [cP] 2 [g/100cm ]

N°

IADC Diam. Nozzle/TFA

Press.

[cc/30"] [cc/30"] 2 [kg/cm ]

Temp.

[°C]

To [m]

C lSalt

[ g/ l] [g/l]

D ri ll ed [ m] Rot. Hrs.

Oil/water Ratio. Sand

Ø

P ar t. L

Rot. hours

P ro gr .L P ar ti al P rog r.

From [m]

R.P.M. W.O.B.[t]

[%]

Flow Rate

[%]

Pressure Ann. vel.

pm/pom pf

Jet vel. HHP Bit

mf

HSI

Daily Losses Progr. Losses

Bottom Hole Assembly N° __________

Serial No.

Water Loss HP/HT

S olid

Run N°

Type

/

[kg/m ]

N°

Description

Gel 10"/10'

pH/ES MBT

Run N°

Data Manuf.

Stock

Total Cost 3

[m ] [m ]

I

O

D

L

I

O

D

L

Daily

B

G

O

R

B

G

O

R

Progr.

Quantity

UM

Supervisor:

Supply vessel

ARPO

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A.3

222 OF 234

0

Casing Running Report (ARPO 03)

RUNNING CASING REPORT


ARPO 03 / B

DATE: Casing type

Operation type

WELL NAME FIELD NAME Cost center

Top [m]

Ø [in]

Bottom [m]

Joint

Length

Progress.

centr.

Joint

Length

Progress.

centr.

Joint

Length

Progress.

centr.

N°

[m]

[m]

(N°)

N°

[m]

[m]

(N°)

N°

[m]

[m]

(N°)

Remarks:

Supervisor

Superintendent

ARPO

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IDENTIFICATION CODE



A.4

223 OF 234

0

Cementing Job Report (ARPO 04B)

CEMENTING JOB REPORT

District/Affiliate Company DATE:

WELL NAME FIELD NAME

ARPO-04 / B

Operation type

Cost center Stage / No.:

Ø [in]

SQUEEZE / PLUG Type

Ø

Length [m]

Cap.[ l/m]

Bottom [m]

Cement retainer

Manufacturer

Model / Type

Squeeze packer

Injectivity Test with:

Pump Rate [l/min] 2

[kg/cm ]

Test

Testing Pr. 2

[kg/cm ]

Ø

De

[inch]

[

Tot. Vol.

Final Sqz Pr.

pumped [l]

[kg/cm ]

Returns

2

[l]

[mins]

Stinger Pressure test Annular pressure CEMENTATION 2

[kg/cm ]

Operation (y/n) Casing Reciprocation

Bump Plug

Casing testing pressure

Casing Rotation

Valve holding

Annulus pressurization

[mins]

Inner string GENERAL DATA Slurry Displacement With

Losses [m3]

To Surface

pumps

Density

Fluid type:

[kg/l] 3

pH

Dumped 3

[m ]

During csg run Circulation

Volume

[m ]

Mud

Mix/Pump Slurry

Density:

[kg/l]

Spacer

Displacement

Duration:

[mins]

Slurry

Opening DV

Final pressure:

2

[kg/cm ]

Circ. through DV Total Circulation / Displacement / Squeeze

Time [mins.] Partial

Supervisor

Progr.

Flow Rate

Pressure

[l/min]

[kg/cm ]

2

Total Volume

Operation Description

Final Press. 2

[kg/cm ]

[l]

Superintendent

Retur Vol.

ARPO

PAGE

IDENTIFICATION CODE



A.5

0

Bit Record (ARPO 05)

BIT RECORD


WELL NAME FIELD NAME ARPO-05

DATE:

Cost center

Run n°

Bit n° Bit size [in] Bit manufacturer Bit type Special features codes Serial number IADC code Depth in [m] Depth out [m] Drilled interval [m] Rotation hrs Trip hrs R.O.P. [m/h] Average W.O.B. [t] Average R.P.M. D.H.M. R.P.M. Flow rate [l/min] 2 St. pipe pressure [kg/cm ] 2

D.H.M. Press. drop [kg/cm ]

Bit HHP HSI Annulus min vel. [m/min]

1

[1/32 in]

J 2 E 3

[1/32 in]

T 4 S 5

[1/32 in]

C

[1/32 in]

[1/32 in] [1/32 in] 2

[in ] T.F.A. B Inner rows [I] I Outher rows [O] T Dull char. [D] Location [L] D Bearing/Seals [B] U Gauge 1/16 [G] L Other chars [O] L Reason POOH [R] Mud type Mud density [kg/l] Mud visc. Mud Y.P. Survey depth Survey incl. Bit Cost Li

Type

%

Stabilizer

Distance

Diameter

from bit

[in]

[m]

tho lo gy

B H A

Currency Pag.:

Supervisor of:

224 OF 234

Superintendent

ARPO

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A.6

225 OF 234

0

Waste Report (ARPO 6)

WASTE DISPOSAL

WELL NAME

Management Report

FIELD NAME

District/Affiliate Company ARPO-06 Cost center

DATE: Report N°

Depth (m)

Mud Type 3

To [m]

Drilled Volume [m ]

Phase size [in]

Cumulative volume [m ]

Cl- concentration (g/l ) 3

3

Usage

3

Phase /Period [m ]

Water consumption Fresh water

Recycled

Cumulative [m ] Total

Fresh water

Recycled

Total

Mixing Mud Others Total

3

3

Fresh water [m ]

Readings / Truck

3

Mud Volume [m ]

Phase

Cumulative

Recycled [m ]

Service

Mixed

Mud Company

Lost

Waste Disposal

Dumped

Transportation

Company

Contract N°

Transported IN Transported OUT

Waste Disposal

Period

Water base cuttings

[t]

Oil base cuttings

[t]

Dried Water base cuttings

[t]

Dried oil base cuttings

[t]

Water base mud

[t]

Oil base mud transported IN

[t]

Oil base mud transported OUT

[t]

Drill potable water

[t]

Dehidrated water base mud

[t]

Dehidrated oil base mud

[t]

Sewage water

[t]

Transported Brine

[t]

Cumulative

Remarks

Remarks

Supervisor

Superintendent

ARPO

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IDENTIFICATION CODE



A.7

226 OF 234

0

Well Problem Report (ARPO 13)

WELL PROBLEM REPORT


ARPO -13

DATE: Problem Code Well

Ø

Situation

WELL NAME Cost center

Top [m]

Start date

Bottom [m]

End date

Measured Depth Top [m]

FIELD NAME

Vertical Depth

Bottom [m]

Top [m]

KOP

Bottom [m]

Open hole

[m]

Mud in hole

Max inclination [°]

Type

@m

Last casing

Dens.[kg/l]:

DROP OFF [m]

Well problem Description

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Supervisor

Supervisor

Supervisor

Remarks at District level:

Superintendent Lost Time Remarks at HQ level

hh:mm Loss value [in currency] Pag. Of

ARPO

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A.8

227 OF 234

0

Malfunction & Failure Report(FB-1)

MALFUNCTION & FAILURE REPORT (FEED BACK REPORT 01)

District/Subsidiary Report Date: Well Name:

Well Code: General Information

Contract No:

Contract Type:

Contractor:

Service/Supply: Drilling

Completion

Workover

Duration Dates of Failure:

Distributed By:

RIG SITE Description of Failure:

Drilling & Completions Company Man: Adopted or Suggested Solution(s):

Contractor Contingency Measures:

Contractor Representative: DISTRICT OR SUBSIDIARY NOTES:

Failure Classification

Status

Technical

Normal

Management/Organisation

Extreme

Safety/Quality

Innovative Adverse

Operations Manager:

Time Lost:

Estimated Cost of Failure:

MILAN HEAD OFFICE NOTES:

Analysis Code:

ARPO

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A.9

228 OF 234

0

Contractor Evaluation (FB-2)

CONTRACTOR EVALUATION (FEED BACK REPORT 02)

District/Subsidiary Report Date:

Well Name:

Well Code: General Information Contract No.: Contract Type: Contractor: Service/Supply: Distributed By: R1 Technical Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (£M): Category Evaluation Score (0-9) Suitability of Equipment and Materials Compliance of Equipment and Materials to the Adequacy of Personnel Meeting with Operational Programme Requirements Meeting with Contract Operation Timings Equipment Condition/Maintenance R2 Management and Organizational Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (£M): Category Evaluation Score (0-9) Availability of Equipment and Materials Technical and Operational Support to Operations Capability and Promptness to Operational Requests R3 Safety and Quality Assurance Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (£M): Category Evaluation Score (0-9) Meeting with the Contract Agreement DSS Availability and Validity of Requested Certificates Meeting with Contract Quality Assurance Terms Event Support Documentation Type of Subject: Issued By: Document:

Notes:

Failure Status Normal Extreme

Operations Manager Drilling & Completions Manager Adverse Innovative

Date:

ARPO

PAGE

IDENTIFICATION CODE



Appendix B - ABBREVIATIONS AC/DC AHTS API BG BHA BHP BHT BJ BMT BOP BPD BPM BPV BSW BUR BWOC BWOW C/L CBL CCD CCL CDP CET CGR CMT CP CR CRA CSG C/T CW DC DE DHM DHSV DIF DLP DLS D&CM DOB DOBC DOR DP DPHOT DRLG DST

229 OF 234

Alternate Current, Direct Current Anchor Handling Towing Supply American Petroleum Institute Background gas Bottom Hole Assembly Bottom Hole Pressure Bottom Hole temperature Blast Joint Blue Methylene Test Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Base Sediment and Water Build Up Rate By Weight Of Cement By Weight Of Water Control Line Cement Bond Log Centre to Centre Distance Casing Collar Locator Common Depth Point Cement Evaluation Tool Condensate Gas Ratio Cement Conductor Pipe Cement Retainer Corrosion Resistant Alloy Casing Coiled Tubing Current Well Drill Collar Diatomaceous Earth Down Hole Motor Down Hole Safety Valve Drill in Fluid Dog Leg Potential Dog Leg Severity Drilling & Completion Manager Diesel Oil Bentonite Diesel Oil Bentonite Cement Drop Off Rate Drill Pipe Drill Pipe Hang off Tool Drilling Drill Stem Test

0

ARPO

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IDENTIFICATION CODE



DV E/L ECD ECP EMS EMW EOC EP ESD ESP ETA ETU FBHP FBHT FC FINS FPI/BO FTHP FTHT GCT GLR GLS GMS GOC GOR GP GPM GPS GR GRA GSS HAZOP HDT HHP HO HP/HT HSI HW/HWDP IADC IBOP ICGP ID IFR IP IPR JAM KMW KOP

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DV Collar Electric Line Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud W eight End Of Curvature External Pressure Electric Shut-Down System Electrical Submersible Pump Expected Arrival Time Endless Tubing Unit Flowing Bottom Hole Pressure Flowing Bottom Hole Temperature Flow Coupling Ferranti International Navigation System Free Point Indicator / Back Off Flowing Tubing Head Pressure Flowing Tubing Head Temperature Guidance Continuous Tool Gas Liquid Ratio Guidelineless Landing Structure Gyro Multi Shot Gas Oil Contact Gas Oil Ratio Gravel Pack Gallon (US) per Minute Global Positioning System Gamma Ray Guidelines Re-Entry Assembly Gyro Single Shot Hazard and Operability High Resolution Dipmeter Hydraulic Horsepower Hole Opener High Pressure - High Temperature Horsepower per Square Foot Heavy Weight Drill Pipe International Drilling Contractor Inside Blow Out Preventer Inside Casing Gravel Packing Inside Diameter Imposta Fabbricazione Ridotta Internal Pressure Inflow Performance Relationship Joint Make-up Torque Analyser Kill Mud Weight Kick Off Point

0

ARPO

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IDENTIFICATION CODE



L/D L/S LAT LC 50 LCDT LCM LCP LEL LMRP LN LOT LQC LTA LTT LWD M/D M/U MAASP MD MLH MLS MMS MODU MOP MPI MSCL MSL MSS MUT MW MWD N/D N/U NACE NB NDT NMDC NSG NTU OBM OD OEDP OH OHGP OIM OMW ORP OWC

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Lay Down Long String Lowest Astronomical Tide Lethal Concentration 50% o Last Crystal to Dissolve C Lost Circulation Materials Lower Circulation Position (GP) Lower Explosive Limit Low Marine Riser Package Landing Nipple Leak Off Test Log Quality Control Lost Time Accident Lower Tell Table (GP) Log While Drilling Martin Decker Make Up Max Allowable Annular Surface Pressure Measured Depth Mudline Hanger Mudline Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Margin of Overpull Magnetic Particle Inspection Modular Single Completion Land Mean Sea Level Magnetic Single Shot Make up Torque Mud Weight Measurement W hile Drilling Nipple Down Nipple Up National Association of Corrosion Engineers Near Bit Stabiliser Non Destructive Test Non Magnetic Drill Collar North Seeking Gyro Nephelometric Turbidity Unit Oil Base Mud Outside Diameter Open End Drill Pipe Open Hole Open Hole Gravel Packing Offshore Installation Manager Original Mud weight Origin Reference Point Oil Water Contact

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ARPO

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IDENTIFICATION CODE



P&A P/U PBR PCG PDC PDM PGB PI PKR PLT POB POOH PPB PPG ppm PTR PV PVT Q Q/A Q/C R/D R/U RBP RCP RFT RIH RJ RKB ROE ROP ROU ROV RPM RPSP RT S (HDT) S/N SBHP SBHT SCC SD SDE SF SG SICP SIDPP SIMOP SPM

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Plugged & Abandoned Pick up Polished Bore Receptacle Pipe Connection Gas Polycrystalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Packer Production Logging Tool Personnel On Board Pull Out Of Hole Pounds per Barrel Pounds per Gallon Part Per Million Piano Tavola Rotary Plastic Viscosity Pressure Volume Temperature Flow Rate Quality Assurance, Quality Control Rig down Rug up Retrievable Bridge Plug Reverse Circulating Position Repeat Formation Test Run In Hole Ring Joint Rotary Kelly Bushing Radius of Exposure Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle Revolutions Per Minute Reduced Pump Strokes Rotary Table High Resolution Dipmeter Serial Number Static Bottom Hole Pressure Static Bottom Hole Temperature Stress Corrosion Cracking Separation Distance Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Shut-in Drill Pipe Pressure Simultaneous Operations Stroke per Minute

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ARPO

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IDENTIFICATION CODE



SR SRG SSC ST STG TCP TD TFA TG TGB TOC TOL TVD TW UAR UGF UR VBR VDL VSP W/L WBM WC WL WOB WOC WOW WP YP

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Separation Ratio Surface Readout Gyro Sulphide Stress Cracking Steering Tool Short Trip Gas Tubing Conveyed Perforations Total Depth Total Flow Area Trip Gas Temporary Guide Base Top Of Cement Top Of Liner True Vertical Depth Target Well Uncertainty Area Ratio Universal Guide Frame Under Reamer Variable Bore Rams (BOP) Variable Density Log Velocity Seismic Profile Wire Line Water Base Mud Water Cut Water Loss Weight On Bit Wait On Cement Wait On Weather Working Pressure Yield Point

0

ENI - Drilling Procedures Manual

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