BJ Services - Cementing Manual

Table of Contents

1

Introduction

Student Manual

2

Casing Cementing

3

Float Equipment & Casing Hardware

4

Stage Cementing

5

Liner Cementing

6

Electronic Engineering Handbook

7

Cement Slurry Volume Calculations

8

Cementing Products

9

Cement Laboratory Testing

10

Absolute Volume Calculations

11

Pressure & Force Calculations

12

Plugback Cementing

13

Squeeze Cementing

14

Squeeze Tools

15

Cementing Equipment

ENG102 Fundamentals of Cement Engineering Version 1.24 Feb 2007

ENG102 Fundamentals of Cement Engineering

Version 1.24 February 2007

Printed: 12/20/2006

EDC, Tomball, TX

Emergency Procedures O

Evacuation Procedure We are Here!

E

Slide 2

EDC, Tomball, TX

1

Emergency Procedures (cont.) O

General Safety Issues ³ 10 mph Speed Limit in BJ Parking Lot ³ Reverse Parking ³ Houston is the 4th largest city in the US ³ Hotel is safe, however! ³ Tobacco Usage Not Allowed in Buildings Ë Smoking Ë Chewing, Dipping, etc.

Slide 3

EDC, Tomball, TX

Van Parking

Facility Plan View

Emergency Muster Point

Slide 4

EDC, Tomball, TX

2

TEDC Facility View Corporate University

Emergency Muster Point “E”

Customer Conference Center

Laboratories

Training Parking Area Slide 5

EDC, Tomball, TX

Welcome! O

Approved Areas ³ Employee Development Center ³ Bathrooms ³ Smoking Area ³ Appointments required anywhere else

Slide 6

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3

First Story Floor Plan

Bathrooms

Leadership & Sales

ENGR Classrooms

Classrooms

Smoking Area Slide 7

EDC, Tomball, TX

Second Story Floor Plan

Admin. Staff

Slide 8

EDC, Tomball, TX

4

A Message From Management O

During this week training is your job. ³ All messages should be handled during your scheduled breaks. ³ Being late to class, late from breaks, or leaving early is unacceptable.

O

Remember you are representing BJ Services during your stay here. ³ Violation of company rules reported by hotel staff, will be reported to both HR and your Manager. ³ Disciplinary actions will be taken against those violating these policies. Slide 9

EDC, Tomball, TX

Classroom Standards O

Standard Classroom Course Procedures ³ Dress Code - Business Casual Ë Ë Ë Ë

No Hats in Classroom No Cut-Off Sleeves Shirts with Collars No shorts or Sandals

³ Cell Phones, Pagers, Beepers ³ Sign-In Procedures ³ Classroom Computer & Laptop Use ³ Return from lunch and breaks punctually Slide 10

EDC, Tomball, TX

5

Course Information O O O

Course will start promptly at 8:30 AM Break Intervals Lunch will be catered in (usually noon) ³ WEAR NAME TAGS ³ Clear tables for next group ³ Drinks are tea & water (if you want soda - take it in from the Training Dept machine)

O O

Finishing time about 5:00 PM Course Outline Slide 11

EDC, Tomball, TX

ENG102 Fundamentals of Cement Engineering: Course Outline O O

O O O

O

O

Casing Cementing Float Equipment and Casing Hardware Stage Cementing Liner Cementing Electronic Engineering Handbook Cement Slurry Volume Calculations Cementing Products

O

O

O

O O O O

Lab Equipment & Procedures Absolute Volume Calculations Pressure and Force Calculations Plugback Cementing Squeeze Cementing Squeeze Tools Cementing Equipment Slide 12

EDC, Tomball, TX

6

Course Information O

Tests and Grading ³ Pretest Ë Test of Current Knowledge – DO NOT GUESS!

³ 3 Daily Tests (50% of Final Score) ³ Final Exam (50% of Final Score) ³ Overall Final Score must be 80% or greater OR ³ Final Exam must also be 80% or greater Slide 13

EDC, Tomball, TX

Class Introductions O

Please introduce yourselves ³ Name ³ Length of service with BJ Services ³ Short career history ³ Place presently assigned ³ Your job title and time in present BJ position ³ Your job responsibilities ³ Knowledge of Cementing

Slide 14

EDC, Tomball, TX

7

Casing Cementing Section 2

Printed: 6/9/2006

EDC, Tomball, TX

Primary Cementing O

Single Stage

O

³ Conductor ³ Surface ³ Intermediate ³ Production ³ Drilling Liner ³ Production Liner

Multiple Stage ³ Surface ³ Intermediate ³ Production ³ Liner

Slide 2

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1

Primary Cementing (cont.) O

Miscellaneous ³ Top Out Surface Casing ³ Inner String ³ Scab* Liner

* Not usually called primary cementing.

Slide 3

EDC, Tomball, TX

Primary Cementing Terminology #1 PLUG DROPPING HEAD CEMENTING MANIFOLD TOP PLUG INTERMEDIATE OR SURFACE CASING CASING IN CASING ANNULUS

EXTERNAL CASING PACKER (OPTIONAL) CEMENT BASKET (OPTIONAL)

BOTTOM WIPER PLUG PREVIOUS CASING SHOE SCRATCHERS OPEN HOLE CASING

CASING/OPEN HOLE ANNULUS

CENTRALIZER FLOW DIRECTION

FLOAT COLLAR SHOE TRACK RAT HOLE

FLOAT SHOE (GUIDE SHOE)

Slide 4

EDC, Tomball, TX

2

Primary Cementing Terminology #2 MUD

SPACER DISPLACEMENT FLUID TOP OF CEMENT (TOC)

LEAD SLURRY PREVIOUS CASING SHOE OPEN HOLE

TAIL SLURRY FLOAT COLLAR SHOE TRACK FLOAT SHOE (GUIDE SHOE)

RAT HOLE

Slide 5

EDC, Tomball, TX

Functions of the Primary Cementing Process O

Principal function ³ Provide a hydraulic annular seal Ë Isolate oil, gas, water zones Ë Restrict fluid movement

³ Additional functions Ë Support casing Ë Protect casing from corrosion Ë Seal off lost circulation zones O

Key to a good cement job ³ Mud Removal Slide 6

EDC, Tomball, TX

3

Conductor Casing O

Characteristics ³ Shallow -- usually less than 100 feet (~30 m) deep ³ Large pipe -- 20" (508 mm) OD up to 36" (914 mm) or larger ³ Must be chained down while cementing

O

Purposes ³ Prevents washing out under rig ³ Is elevation for bell nipple and flow nipple Ë Establish returns to surface Ë Direct returns to mud pits

³ Not always required

Slide 7

EDC, Tomball, TX

Conductor Casing (cont.) O

Cements used ³ Accelerated A, G, H, or construction cement ³ Ready mix concrete sometimes used

O

Cementing Procedures ³ If no wiper plugs used, just displace casing ³ Often cemented through drill pipe (Inner String)

Slide 8

EDC, Tomball, TX

4

Typical Deep Well Casing Program Conductor Conductor 40' to 1,500‘ (12 m – 450m)

Slide 9

EDC, Tomball, TX

Surface Casing O

Characteristics ³ Required by Governing Body in area ³ 100' (30 m) to 5,500' (1,500 m) or deeper ³ OD from 7-5/8" (193.7 mm) up to 20" (508 mm) or larger ³ May need chaining down while cementing ³ Should circulate cement back to surface Ë Hole may be severely eroded Ë Lost circulation may be a big problem

Slide 10

EDC, Tomball, TX

5

Surface Casing (cont.) O

Purposes ³ Protect fresh water sands ³ Provide place to mount ("nipple up") B.O.P.s ³ Case unconsolidated formations ³ Seal off lost circulation zones ³ Support later casing strings

O

Cements used ³ Lead (filler) followed by high strength tail-in ³ High strength cements on deeper surfaces Slide 11

EDC, Tomball, TX

Casing Head O

Lowest part of the wellhead assembly, connected to the surface casing ³ Supports BOP while hole is drilled for the next casing string ³ Provides for suspending and sealing (packing off) the next casing string ³ Provides outlets for annular access ³ Provides for testing BOPs ³ Threaded or welded connection to surface casing Slide 12

EDC, Tomball, TX

6

Surface Casing (cont.) O

Cementing Procedures ³ Bottom and top wiper plugs should be used ³ Often cemented through drill pipe ³ Centralize & thread-lock bottom joint & subs ³ Sometimes followed by a “top-out” job

Slide 13

EDC, Tomball, TX

Typical Deep Well Casing Program Surface Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Slide 14

EDC, Tomball, TX

7

Surface Casing Job (Typical - API) 12¼” Hole 8-5/8” 24# J-55 Casing

Fresh Water

Class “H” Cement with 2% CaCl2 65% Excess

8.34 ppg Float Collar @ 510 ft Float Valve Guide Shoe @ 550 ft

9.5 ppg Mud

Total Depth @ 580 ft Slide 15

EDC, Tomball, TX

Surface Casing Job (Typical-Metric) 308 mm Hole 219.1 mm 35.72 kg/m J-55 Casing Float Collar @ 155 m

Fresh Water 1000 kg/m3

Normal Portland Cement with 2% CaCl2 65% Excess

Float Valve Guide Shoe @ 170 m

1140 kg/m3 Mud

Total Depth @ 180 m Slide 16

EDC, Tomball, TX

8

Texas RRC Surface Casing Regulations

Slide 17

EDC, Tomball, TX

US Regulatory Requirements O

Federal Regulatory Requirements ³ U.S. Environmental Protection Agency (EPA) ³ Department of the Interior's Bureau of Land Management (BLM) ³ Minerals Management Service (MMS)

O

State Regulatory Requirements Ë Examples: ¸ Railroad Commission of Texas (RCC) ¸ New Mexico Energy, Minerals & Natural Resources, Department Oil Conservation Division. (OCD) ¸ Oklahoma Corporation Commission (OCC), Oil and Gas Conservation Division (OGCD) ¸ Louisiana Department of Natural Resources (DNR) ¸ Colorado Oil and Gas Conservation Commission (COGCC) ¸ California Department of Conservation's Division of Oil, Gas, and Geothermal Resources

Ref: http://web.ead.anl.gov/dwm/regs/index.cfm#state

Slide 18

EDC, Tomball, TX

9

Intermediate Casing O

Characteristics ³ 4,000' (~1,000 m) to 16,000' (~5,000 m) or more (wide range) ³ Size: 6-5/8" (168.3 mm) up to 20“ (508 mm); 9-5/8" (244.5 mm) very common ³ Often circulate cement back to surface Ë Sometimes only into surface pipe Ë Rarely cement only bottom section

³ Completion may be made in intermediate

Slide 19

EDC, Tomball, TX

Intermediate Casing (cont.) O

Purposes ³ Case off critical zones Ë Lost circulation Ë High pressure Ë Salt zones

³ B.O.P.s always installed ³ Support later casing strings

Slide 20

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10

Intermediate Casing (cont.) O

Cements and procedures ³ Slurries too varied to generalize ³ Common to run filler and high strength tail ³ Bottom and top wiper plugs should be used ³ Sometimes cemented through drill pipe ³ Sometimes done in stages

Slide 21

EDC, Tomball, TX

Wellhead O

Casing Hanger ³ Transfers casing weight to the casing head (or spool) ³ Provides an annular seal at surface Ë May use a separate casing seal

O

Casing Spool ³ Allows subsequent casings to be hung

Slide 22

EDC, Tomball, TX

11

Typical Deep Well Casing Program Intermediate Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Intermediate 4,000' to 16,000‘ (1,200 m to 5,000 m)

Slide 23

EDC, Tomball, TX

Production Casing O

Characteristics ³ 1,700' (500 m) to 20,000' (6,000 m) or deeper ³ Common sizes: 4-1/2“ (114.3 mm), 5-1/2“ (139.7 mm), and 7“ (177.8 mm)

O

Purposes ³ Complete well for production ³ Provide pressure control ³ Cover worn or damaged intermediate Ë Full string of undamaged casing Ë Well control when perforating Slide 24

EDC, Tomball, TX

12

Production Casing (cont.) O

Cements used ³ Lead (filler) followed by high strength tail-in ³ High strength cements across all pay zones

O

Cementing Procedures ³ Good spacer commonly used ³ Common to displace with perforating fluid ³ Good practice to flush pumps/lines before displacing

Slide 25

EDC, Tomball, TX

Typical Deep Well Casing Program Production Casing Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Intermediate 4,000' to 16,000‘ (1,200 m to 5,000 m) Production Casing 5,000' to 20,000‘ (1,500 m to 6,000 m)

Slide 26

EDC, Tomball, TX

13

Liner Casing O

Characteristics ³ Come in several varieties Ë Drilling liner Ë Production Liner Ë Others

³ 4,000' (1,200 m) to 20,000' (6,000 m) or deeper ³ Usual sizes: 4-1/2" (114.3 mm), 5-1/2“ (139.7 mm), 7“ (177.8 mm), and 7-5/8“ (193.7 mm)

Slide 27

EDC, Tomball, TX

Liner Casing (cont.) O

Purposes ³ Well control ³ Faster installation than full string ³ Lower initial cost than full string ³ Cover worn or damaged intermediate ³ Other reasons

Slide 28

EDC, Tomball, TX

14

Typical Deep Well Casing Program Drilling Liner Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Intermediate 4,000' to 16,000‘ (1,200 m to 5,000 m) Drilling Liner 5,000' to 20,000‘ (1,500 m to 6,000 m)

Slide 29

EDC, Tomball, TX

Typical Deep Well Casing Program Tie-back Stub-Liner Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)


Tie-back Stub Liner

Slide 30

EDC, Tomball, TX

15

Typical Deep Well Casing Program Production Liner Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)


Tie-back Stub Liner

Production Liner 6,000' to 25,000‘ (1,800 m to 7,500 m) Slide 31

EDC, Tomball, TX

Typical Deep Well Casing Program Tie-back Casing Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)


Tie-back Stub Liner Tie-back Casing Production Liner 6,000' to 25,000‘ (1,800 m to 7,500 m) Slide 32

EDC, Tomball, TX

16

Stage Cementing O

Important variation of primary cementing ³ Two Stage (2-stage) Ë Jobs routinely done as 2-stage ¸ Intermediate ¸ Production (and liner, recently)

Ë Basically same as other casing cementing ¸ Bottom stage cemented ¸ Stage tool opened ¸ Top stage cemented through tool ports

³ Three Stage (3-stage), (4-stage ?) ¸ Same basic principles

Slide 33

EDC, Tomball, TX

Stage Cementing (cont.) O

Purposes ³ Prevent fracturing formation -- hydrostatic psi ³ Cover select zones without full cement column ³ Cement above lost circulation zone ³ Reduce chance of collapsing casing ³ Deal with major temperature differentials

O O

Cements used vary -- as per objectives Cementing Procedures -- open tool A.S.A.P. Slide 34

EDC, Tomball, TX

17

Two-Stage Cementing

2nd STAGE

1st STAGE Slide 35

EDC, Tomball, TX

Outer String Cementing O

Other common names ³ ³ ³ ³ ³

O

Top job Top out One inch Macaroni string Spaghetti string, etc.

ACCELERATED CEMENT

Small diameter ³ line pipe ³ or tubing ³ or D.P.

Slide 36

EDC, Tomball, TX

18

Outer String Cementing (cont.) O

Run pipe as deep as possible between casing & hole ³ Usually 100 ft (30 m) or deeper Ë Sometimes only 20 to 60 feet (6 m to 20 m) will go Ë Has been run to 3,400 feet (1,000 m)

³ Mix accelerated cement down 1" (25.4 mm) pipe ³ At full returns stop mixing, pull & wash pipe

Slide 37

EDC, Tomball, TX

Outer String Cementing (cont.) O

To fill annulus and around top of surface casing ³ When returns were lost ³ When cement fell after job ³ To strengthen around top of casing in any case

Slide 38

EDC, Tomball, TX

19

Inner String Cementing O

O

O

Large diameter casing run to T.D. Drill pipe run inside casing -- stinger fits in collar Special float collar or shoe to accept stinger ³ Tag-in (sometimes called "stab-in") ³ Latch-in ³ Screw-in Slide 39

EDC, Tomball, TX

Inner String Cementing (cont.) O

O

O

O

Plug may or may not be used Caution must be taken with casing collapse Mix and pump cement until it circulates to surface (no waste) Reduces displacement volume and time

Slide 40

EDC, Tomball, TX

20

Inner String Equipment

Note: Also see Inner String equipment in the Davis Lynch and Weatherford EQUIPMENT CATALOGS in Section 7 of student work book (manual). Slide 41

EDC, Tomball, TX

References O

Casing Hardware Ë Davis-Lynch Catalog Ë Weatherford Catalog

O

Surface Equipment (Wellhead & BOP) Ë FMC Technologies ¸ http://www.fmctechnologies.com/SurfaceWellhe ad.aspx

Ë Vetco Gray Inc. ¸ http://www.vetcogray.com

Ë Cooper Cameron Corp. ¸ http://www.coopercameron.com

Ë Hydril Company LP. ¸ http://www.hydril.com

Slide 42

EDC, Tomball, TX

21

Float Equipment and Casing Hardware

Section 3 Printed: 6/13/2006

EDC, Tomball, TX

Casing Equipment O O

Casing Shoes ³ Guide, Float

O

Float Collars ³ Types

O O O O O

Centralizers Scratchers Baskets Plugs Cement Heads

Revised 01/13/2004

Slide 2

EDC, Tomball, TX

1

Casing O

Sizes (Nominal OD) ³ 30”, 20”, 13 3/8”, 9 5/8”, 7 5/8”, 5” ³ 508 mm, 339.7 mm, 244.5 mm, 177.8 mm, 139.7 mm ³ Many other combinations

O

Weight (lbs/ft & kg/m) ³ Determines wall thickness and ID

O

Grade ³ J-55, N-80, P-110, etc Ë Number denotes minimum yield strength of the steel Ë Together with weight determines mechanical properties ¸ Burst, Collapse, Yield

Revised 01/13/2004

Slide 3

EDC, Tomball, TX

Casing O

Threads ³ CSG - API Short Round ³ LCSG - API Long Round ³ BCSG - API Buttress (Squared Threads) ³ XCSG - API Extremeline (no collar, has shoulder) ³ Premium - Many proprietary types Ë Hydril, VAM, etc.

O

API Specifications ³ Standard sizes, weights, grades, threads ³ Non-API casing should exceed API specs

Revised 01/13/2004

Slide 4

EDC, Tomball, TX

2

Casing

Revised 01/13/2004

Slide 5

EDC, Tomball, TX

Guide Shoe O

O

Cement Nose

Texas Pattern

O

O

Sawtooth

Revised 01/13/2004

Downjet

Run on the bottom of the casing Used to guide the casing into the hole Hollow center allows mud to flow into casing when run in hole No floatation device

Slide 6

EDC, Tomball, TX

3

Float Shoes and Collars O

Floatation Devices ³ Have some type of device which acts as a check valve to prevent cement from flowing back into casing due to differential pressure

O

Float Shoes ³ In addition to the valve, help guide the casing into hole

O

Float Collars ³ Generally placed 1 - 2 joints above the shoe (40 to 80 ft [13 to 26 m] ). This is where the plugs bump.

Revised 01/13/2004

Slide 7

EDC, Tomball, TX

Float Shoes and Collars O

Shoe Track (Shoe Joint) ³ Area between the shoe and the collar ³ Safety factor to insure good cement around the outside of the shoe

O

Thread Lock ³ Devices are screwed on casing and “glued” Why?

O

Floatation Device Types ³ Manual Fill ³ Differential Fill ³ Auto Fill

Revised 01/13/2004

Slide 8

EDC, Tomball, TX

4

Float Shoe

Flapper Valve Float Shoe Revised 01/13/2004

Poppet Valve Float Shoe

Double Valve Float Shoe Slide 9

EDC, Tomball, TX

Float Collars

Flapper Valve Insert Float Poppet Valve Float Collar

Revised 01/13/2004

Slide 10

EDC, Tomball, TX

5

Differential Fill Floats O O O O O O

At set differential pressure will allow fill from below Maintains casing about 90% full when RIH Saves rig time and money Reduces chances of sticking Reduces annular pressure surges Converted prior to cementing

Revised 01/13/2004

Slide 11

EDC, Tomball, TX

Auto Fill Floats O O O O O

Float valve is locked in open position while RIH Casing automatically fills from bottom Saves rig time and money Virtually eliminates annular surge pressure Converted prior to cementing ³ Drop ball or circulating pressure

Revised 01/13/2004

Slide 12

EDC, Tomball, TX

6

Centralizers

Slim Hole Centralizer

Revised 01/13/2004

Slide 13

EDC, Tomball, TX

Centralizers

Turbolizer

Semi Rigid

Revised 01/13/2004

Rigid

Solid

Slide 14

EDC, Tomball, TX

7

Centralizers

Long & Short Solid Spiral

Low Torque

Low Drag

Revised 01/13/2004

Slide 15

EDC, Tomball, TX

Stop Collars

Hinged Crossbolt

Hinged with Locking Pins Slip On with Set Screws

Revised 01/13/2004

Slide 16

EDC, Tomball, TX

8

Centralizers

W

RH

100 % Stand-off is fully centralized pipe Minimum recommended Standoff is 67%

RC w % Stand-off =

w

x 100

RH - R C Revised 01/13/2004

Slide 17

EDC, Tomball, TX

Centralizers O O O

Preferred type for normal conditions are “non-weld” Place over stop collar API RP 10D ³ Specifies Centralizer and Stop Collar testing Ë Starting Force Ë Moving Force Ë Restoring Force

³ Recommends Placement criteria O

CMFACTS ³ Includes Centralizer placement module

Revised 01/13/2004

Slide 18

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9

Scratchers

Wire Finger Reciprocating

Wire Cable Rotating

Cable Loop Reciprocating Revised 01/13/2004

Slide 19

EDC, Tomball, TX

Cement Baskets

Revised 01/13/2004

Slide 20

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10

Stage Collar

CLOSING SLEEVE PORT O-RING OPENING SLEEVE BRASS SHEAR BALL

Revised 01/13/2004

Slide 21

EDC, Tomball, TX

Cementing Wiper Plugs

Latch-Down Anti-Rotation Plugs

Revised 01/13/2004

³ Weatherford and Davis-Lynch Plugs

Slide 22

EDC, Tomball, TX

11

Cementing Wiper Plugs Conventional or Anti-rotational

O

³ Anti-rotational must be paired with float equipment

Bottom Plugs are hollow

O

³ BJ Bottom Plugs are RED or YELLOW

Top Plugs are solid

O

³ BJ Top Plugs are BLACK ³ Construction is rubber with rubber, plastic or aluminum cores Revised 01/13/2004

Slide 23

EDC, Tomball, TX

Fas-Lok Plug Containers (Cementing Head)

LIFTING CHAIN TATTLETALE GLAND

O-RING & BACKUP RING

TATTLETALE GLAND

2"-1502 FEMALE SUB

LIFTING CHAIN O-RING & BACKUP RING 2"-1502F B

C

A A

B

C C

FLAG TATTLETALE

FLAG TATTLETALE

Revised 01/13/2004

PIN PULLER Slide 24

EDC, Tomball, TX

12

Manifold for Double Plug Container

Revised 01/13/2004

Slide 25

EDC, Tomball, TX

Subsea Cementing

LIFTING CHAIN P/N 124304

O-RING PART N0. XAS-351-01

PIN PULLER FOR DART RELEASE

PIN PULLER FOR BALL RELEASE

(B) O-RING (A) O-RING UPPER MANDREL P/N 119024

(C) O-RING

(D) O-RING

CASE P/N 119767

3 1/4"-12

2.75" I.D. REF. PISTON P/N 119796 SWIVEL ASSEMBLY EXTENSION SPLIT RING 119022 P/N 119766 SPLIT RING RET. 119023 Revised 01/13/2004

3 1/2"-8 LPT (ADAPTER P/N 124347)

Slide 26

EDC, Tomball, TX

13

Casing Hardware References O O O O

BJ Iron Manual (BJIronMan.nsf) Davis-Lynch (www.davis-lynch.com) Weatherford (www.weatherford.com) Frank’s (www.antelopeoiltool.com)

Revised 01/13/2004

Slide 27

EDC, Tomball, TX

14

D r i l l i n g

&

I n t e r v e n t i o n

F l o a t E q u i p m e n t

&

S t a g e C a t a l o g

2 0 0 3

table of contents

Research & Development Quality Manufacturing Float Equipment Guide Shoes

2003 Float & Stage Catalog

1 2 3 4

Stage Tool Accessories

28

Liner Accessories

29

Pack-Off StageTool System

30

Cement Wiper Plugs

31

Sure-Seal 3™ Float Valves

5

Sub-Surface Release Wiper Plugs

Sure-Seal 3™ Float Shoes

6

ReamerShoe™ Tools

34

Centralizers

35

Centralizers For Horizontal Applications

36

Sure-Seal 3™ Float Collars Auto-Fill Float Equipment

9 12

32

Auto-Fill & Differential Fill Float Equipment

14

Special Tools for Horizontal Applications

38

Special Collars

15

Charts & Dimensions

40

Stab-In Float Equipment

16

Insert Float Equipment

18

Tubing & Small Float Equipment

19

MudMaster™ System

20

MudMaster™ Filter Shoe Joint

21

Centralizer Sub Float Equipment

22

Mechanical Stage Tools

24

Hydraulic Stage Tools

26

© Copyright 2003 Weatherford, all rights reserved


Research & Development

Weatherford offers a complete line of precision-made float and stage equipment to satisfy the needs and preferences of the oil and gas industry. Weatherford is committed to providing only high-quality products. Our comprehensive quality assurance program includes: • Use of only high-quality tubulars. • Strength tests for every batch of concrete. • Functional tests on all valves, stage-cementing and packer equipment. • A dedicated R&D Engineering Group constantly working on new tools committed to reducing operator costs. This commitment to quality maintains Weatherford as the industry leader in float equipment. When it comes to developing and testing equipment for use in the Primary Cementing phase of your well, Weatherford is the leader. We have full scale vertical and horizontal test wells in Houston, Texas and Aberdeen, Scotland in which equipment is tested. Weatherford also has two mud flow loops, one in Houston, Texas and another in Houma, Louisiana, with associated testing equipment to simulate most downhole conditions encountered by float equipment. These mud flow loops (MFL) and high temperature cells allow Weatherford to routinely test equipment to API Recommended Practice 10F, and to perform specialized customer tool testing on request. The MFL uses drilling fluids containing sand (to simulate abrasive solids) to test float and stage equipment. The MFL is capable of monitoring the effects of pressure, flow rate, and temperature on a 24-hour basis, so that performance characteristics can be predicted on all types of equipment. Weatherford’s Engineering Team regularly monitors all types of float, stage and wiper plug equipment for the following:

• Temperature resistance: the abilty of a valve to maintain a seal at elevated temperatures. • Pressure loss: measured while flowing at rates up to 1,000 gpm with mud and/or cement. • Fill rates/pressures: used in auto-fill and differential valve development and testing as per API RP10F. • Sealing flow rate: the reverse flow rate that causes the float valve to seal (applicable to non-spring loaded valves only). • Function testing of the non-rotating plugs in conjunction with non-rotating float equipment. • Sub-Surface Release Plug functions under different types of downhole conditions.

• Maximum back-pressure: what pressure is held by the valve and concrete. • Maximum bump-pressure: what pressure is held by the concrete when the wiper plugs bump and test the casing. • Flow endurance: how well a valve resists structural damage from fluid erosion and fluid cutting.


Mud Flow Loop at Weatherford’s Testing and Training Facility, Houston,Texas

Quality Manufacturing


Weatherford offers a complete range of products serving the needs of our customers for the purpose of running and performing the primary cementation of their casing and tubing strings. At one time this just meant providing centralizers and float equipment. Today, it means a full and expanding product line with over 10,000 different products. Quality cementation has been and will continue to be crucial to successful cementing and to the ultimate return-on-investment of the well. Weatherford offers not only a complete range of products, but also the manufacturing and field support required to meet current and future needs. Our products represent significant engineering advances, the result of unparalleled expertise in cementation products. Our investment in state-of-the-art computer technology and product development has produced the most advanced float and stage equipment products on the market today.

CNC Equipment

Our experience in producing float equipment and our commitment to manufacture accurately and efficiently using Computer Numerically Controlled (CNC) equipment have made Weatherford a leader in manufacturing technology and capability. We offer fast delivery of custom-built and premium threaded equipment. With every order of equipment that you buy from Weatherford, you know that we have made every effort to provide you with products that measure up to your most stringent requirements because we take great pride in what we put our name on. Our manufacturing procedures are in accordance with international quality standards, including API Q1 and ISO-9001.

CAD Systems

Houma, Louisiana Facility



Float Equipment

Advantages: • Drillability of plugs and float equipment is easy and fast with either conventional rotary bits or PDC bits. • WiperLok® system provides a proven anti-rotational mechanism and is available in both standard as well as Sub-Surface Release plugs ( SSR™ Plugs ). • Withstands long periods of circulation with highly abrasive fluids. • Top and bottom plugs rated to 80% of burst pressure for most standard weight and grade casing. • Polyurethane plug material is resistant to wear, making it ideal for long casing strings.

Sure-Seal 3™ Float Equipment The Sure-Seal 3 float equipment, an integral part of the WiperLok system, incorporates a PDC drillable, spring-loaded, phenolic plunger valve. The equipment features include: • Exceeds API RP10F Category IIIC casing float equipment flow endurance, pressure and temperature requirements. • Available in an ultra-high pressure configuration that incorporates a phenolic landing plate. This landing plate provides an anti-rotation mechanism, and evenly distributes forces across the top of the float equipment. • Large flow area minimizes pressure drop and erosion during circulation. • Operates in deviated or horizontal wells where differential pressures may be lower. • Easily drilled, non-ferrous spring (.091 or .114 wire diameter) ensures immediate plunger seating after conversion when circulation or displacement is stopped. • Resilient low pressure seal assures positive shut-off when differential pressure is low or non-existent. Hard phenolic high pressure seal minimizes extrusion and stress damage to the resilient seal at extreme differential pressures. Phenolic plunger contains no metallic components, assuring PDC bit drillability. • Special design uses fluid hydraulics to draw plunger firmly into retainer cup, minimizing spring fatigue and reducing plunger contact with the side wall. This results in less erosion damage from high velocity flow.


• Sure-Seal 3 valves come in three sizes to optimize flow areas. • Available with PDC drillable landing plate in collars or shoes as required. • Available in sizes 4” and larger.

Guide Shoes


The primary purpose of Weatherford guide shoes is to guide the casing to cementing depth and reinforce the lower end of the casing. Orifices are sufficiently large as to allow most tripping balls, orifice tubes and debris to exit the casing without obstruction.

Cement Nose Guide Shoe - Model 202 • A rounded cement nose with a generous radius which assures smooth running. • A special formula cement maximizes shock resistance and minimizes drill-out time.

• This tool is PDC drillable. • An alternative version L202 Large Bore will be shown with the L series of float collars.

Downjet Cement Nose Guide Shoe - Model 222 • This guide shoe allows circulation primarily through the central orifice, but has multiple side ports. • The Model 212 guide shoe with up-jets is also available to provide better displacement mechanics during cementation.

• This tool is also PDC drillable. • Down-jets in the model 222 guide shoe promote washing down.

Composite Nose Guide Shoe - Model 202WM • The newest development in float equipment nose configurations is the eccentric and concentric versions of the composite nose.

• The composite nose material is completely PDC drillable.

• Shown here in the eccentric version, this guide shoe helps the casing or liner string get past ledges and other downhole obstructions.

Texas Pattern Guide Shoe - Model 112 • This guide shoe has an internally beveled edge design. • It is constructed to prevent drilling and wireline tools from hanging up.

• It can be used to wash down through obstructions in the wellbore while running openended pipe.

Saw Tooth Pattern Guide Shoe - Model 105 • This guide shoe model features a saw tooth design on its leading edge. • It is designed for lightly reaming through bridges and fill materials but not active drilling.

• As with all guide shoes, it is most often run with a float collar one to two joints above.



Sure-Seal 3™Float Valves

Sure-Seal 3 Float Valves As pictured below, the Sure-Seal 3 valve is offered in three distinct sizes. Each valve has been stringently tested to the highest performance levels and have set the standards for reliability. The smallest valve (pictured at left) was engineered to maximize flow in small casing applications. This PDC drillable plastic valve is placed in standard shoes and collars from 4" to 5-1/2" and can be used in both single or double valve configurations. This valve is rated to 400°F and 10 bbl/min. flow rate for 24 hours. The medium Sure-Seal 3 features a minimum of over 3 square inches flow area to allow passage of large cuttings and debris. As with its smaller counterpart it is rated to 5,000 psi at temperature and after extended flow periods. This valve is used in equipment from 7-5/8" to 5-1/2". The largest valve, the 3-1/4" Sure-Seal 3, is used in all standard float equipment sizes 8-5/8" and above. In special circumstances this valve can be placed in equipment down to 7" when lost circulation material or high circulation rates are expected. This valve features a greater than 4.9 square inch minimum flow area and has been used in every major oil field around the world. Regardless of which of the three world-class valves is placed in the equipment for your well, you can be assured of the highest quality on the market.


Sure-Seal 3™Float Shoes


Advantages: • Sure-Seal 3 Valves are the foundation of most Weatherford conventional float equipment. • The valve and cement around it is capable of withstanding long periods of circulation. Sure-Seal 3 Float equipment exceeds API RP10F Category IIIC flow endurance and pressure test requirements. • Float shoes are most often run with float collars and must perform the primary function of guiding the casing to total depth while also serving as the primary valve when the cementation displacement is completed. • The Sure-Seal 3 Shoe design assures quick PDC drillability. • Shoe designs vary depending upon hole geometry, formation pressure, bore hole stability and operator preference.

Cement Nose Float Shoe - Model 303 • The Sure-Seal 3 float shoe features our PDC drillable spring-loaded poppet valve. • The shoe's rounded nose assists the running of casing in horizontal or deviated wells. • It is ideal for use with low differential pressures where other valves may not seal.

Downjet Float Shoe - Model 323 • It delivers a jetting action that is effective in washing out bridges and distributing the cement slurry evenly at the shoe to minimize channeling. • The downjet shoe provides ample circulation area if the casing is plugged off on the bottom. • The model 323 features no ferrous components and is PDC drillable.



Sure-Seal 3™ Float Shoes

Double Valve Float Shoe - Model 303DS • The Sure-Seal 3 double valve float shoe has all of the features of the standard float shoe and provides the added assurance of sealing when debris prevents the upper valve from closing.

• This model is PDC drillable, and is recommended when no other float equipment is to be run.

• Most often it is used when the operator does not want to run a collar and drill cement in the shoe track.

Double Valve Upjet Float Shoe - Model 313DS • Features two valves for security. • The model 323 DS is also available featuring downjet ports.

• Circulating ports can be ordered as downjet or upjet versions.

Double Valve Bladed Nose Float Shoe - Model 329DS • The Sure-Seal 3 liner float shoe is available in a single (Model 329) or double valve (Model 329DS) design.

• This model provides ample circulation when the casing is resting on the bottom.

• It is constructed so that the bladed nose prevents rotation of the mechanical liner hanger during setting operations.

• This type of nose is not designed for drilling or reaming.

• The nose is built of aluminum for easy drillout. The nose has blades and jets that are effective in washing through bridges.


Sure-Seal 3™Float Shoes


Downjet Float Shoe with Centralizer Vanes - Model 323C • The Model 323C combines the proven Sure-Seal 3 technology with the guaranteed standoff provided by rigid vanes. • Centering the casing at the shoe assists drag reduction and getting past ledges when the casing is being run into the wellbore.

• Rigid blades can be coordinated with rigid centralizers to provide positive casing stand off while minimizing drag.

Centralizer Sub Float Shoe with Composite Eccentric Nose - Model 453WM • Same benefits of 303 Float Shoe, but built within a Centralizer Sub with integral bow spring centralizer blades and a composite nose. • Centralizes the pipe at the critical shoe area for optimum mud displacement.

• Built to guide casing strings down through extremely tight casing and wellhead restrictions then opening into a larger underreamed wellbore.

Composite Eccentric Nose Downjet Float Shoe - Model 323WM • Same superior valve float shoe but now combined with an eccentric, composite nose to give all the advantages for getting past ledges or obstructions downhole.

• Same superior PDC drillability.

• Optional jet orientations are available up, down or both.



Sure-Seal 3™ Float Collars

Advantages Float Collars serve several very important roles in the primary cementation phase of the casing string. • Act as a back-up valve to the one located in the float shoe, or primary valve when guide shoes or MudMaster™ Filter Shoes are run. • The float collar provides a landing point for the casing wiper plugs, whose function it is to wipe any mud film from the casing during the cement displacement. The float collar allows this contaminated cement to be captured in the shoe track instead of being pumped into the annulus. • Pressure holding capability of a float collar when a plug bumps against it is referred to as bump pressure, while pressure from the annulus on the back side of the valve is called back pressure. • Bumping of the wiper plug confirms to the operator that the displacement is complete. The valve and cement around it are capable of withstanding long periods of circulation. • The Sure-Seal 3 design assures PDC drillability.

Float Collar - Model 402 • Steel shell, made from collar stock for greater strength than the casing on which it is run. • Single poppet style Sure-Seal 3 valve. • High strength concrete for maximum resistance to circulating erosion, as well as bump and back pressures. • Completely PDC drillable. Fastest drillout usually occurs with low WOB and high RPM with PDC bits. • This piece of float equipment meets and exceeds the API RP10F's highest test criteria, that is the III-C rating. The API RP10F test includes a 24-hour flow test at 10 bbl/min, and a 5,000 psi back pressure test after 400°F temperature exposure for 8 hours.


Sure-Seal 3™Float Collars


Float Collar with Non-Rotating Landing Plate - Model 402P • A superior float collar for both back pressure capability and drillability due to its rugged design and the Sure-Seal 3 valve. • Features a phenolic non-rotating plate on which a multi-tooth non-rotating wiper plug will land. • The throat section of this type of float collar is lined with a phenolic tube giving it added erosion resistance as well as added length. This added length increases the back pressure and bump pressure ratings. • Non-ferrous internal components keeps this equipment PDC compatible.

Float Collar with Non-Rotating Landing Plate - Model 402NP • Slightly shorter than the 402P, this float collar features the same Sure-Seal 3 valve. • The orifice between the non-rotating plate and the valve is slightly shorter and made of concrete. • Overall reduced length lowers the maximum bump pressure but still retains the API RP 10F III-C ratings. • The non-rotating landing plate prevents plug rotation during drillout.

Pressure Rating Charts on Page 41



Sure-Seal 3™ Float Collars

Double Valve Float Collar with Non-Rotating Landing Plate - Model 402PD • Just as in the flat profile float shoes and collars, there is an option for double Sure-Seal 3 valves when an operator wants that added insurance. • The non-rotating plate is mounted on top of a phenolic throat section. The pressure ratings of this float collar match or exceed that of the 402P. • This model is PDC drillable.

Sure-Seal 3 Float Collar with Centralizer Vanes - Model 402C • Special float collars are also available with integral blades. These blades are not welded on, but rather milled from a larger OD stock. Blade options are available for straight and spiral configurations. • All collars are made from collar stock to avoid any localized hardening generated by welding on high-grade alloys. • Non-rotating landing plate and bow-spring versions are available on request.


Auto-fill Float Equipment


Auto-fill float equipment is used when the operator wants his casing to fill with drilling fluid while it is being lowered into the wellbore. This fluid contains a certain amount of drilled solids; therefore, the orifices and valves must be designed to be unaffected by debris. The most common reason for running auto-fill float equipment is to prevent surge pressure build up or the piston effect. Another reason for running auto-fill valves is to prevent casing collapse due to external pressures not being balanced with fluids being manually added. All of these problems could be addressed by modifying the trip speed. However, the use of auto-fill float shoes and collars saves the operator time and money by allowing the pipe to be lowered at a faster pace than normal.

Large Bore Auto-Fill Float Collar - Model L42A • Auto-Fill tube assembly made of composite materials to reduce metal content.

• Optional ball seats available for ball sizes from 1 ½" to 3 ½" diameter.

• Large, open bore tube for solids tolerance and surge reduction.

• Low conversion pressure.

• Two valves for security allow this float collar to be run with L202 Guide Shoes or Filter Shoes. • Ball-activated conversion to check valves.

• Valves have over 4" bores after conversion. • PDC drillable non-ferrous components with non-rotating profile to facilitate drill-out of cementing plugs.

Auto Fill and conversion sequence for L42A Float Collar

Large Bore Guide Shoe - Model L202 • The primary purpose of this guide shoe is to guide the casing to depth when run with large bore float equipment.

• The large orifice is also designed to allow the conversion ball and tube to pass without hindrance through the guide shoe.

• Another advantage is allowing a maximum amount of fluid to pass into the casing and be debris tolerant.

• The guide shoe is designed to allow ample flow area should the composite tube rest on the cement rather than pump through.



Auto-fill Float Equipment

Flow-Activated Large Bore Circulating Auto-Fill Float Collar - Model L45AP • Trapped ball design allows operator to run this auto-fill float equipment (flow-activated check valve) with the ball always in place ready for conversion using flow rate. • Uses large bore technology for solids tolerance and surge reduction. • Can be used in high deviation wellbore profiles. • Optional conversion rates available • Up to 4 bbl/min circulating rate prior to conversion with 5 to 8 bbl/min de-activation flow rate at 500 to 700 psi.

• Non-rotating profile facilitates drillout of cementing plugs. • Designed to meet API RP10F Category III B - 3000 psi. • This tool is also available in a non-circulating version, the Model L46AP. The non-circulating model does not have flow ports in the composite Auto-Fill tube. • This equipment is PDC drillable.

• Valves have 3.125" Auto-Fill diameter and 4" bores after conversion.

Auto fill and conversion sequence for L45AP Float Collar


Auto-Fill & differential Fill Float Equipment


Auto-Fill Float Collar - Model 455BB • This auto-fill valve is available in 4.5” and larger casing and liner sizes. • The valve has a maximum orifice size of 2" and can be reduced if necessary. Surge reduction for smaller casing sizes is provided with this valve. • After conversion the trip ball is free to activate other ball activated equipment below. • High-angle guide version is recommended for well bore inclinations greater then 25%.

• The shoe version of this equipment (not shown) is the 355BB. Both can be converted with one ball. • Both the 355BB and the 455BB are PDC drillable. • You can run a guide shoe with this collar but always confirm that the orifice is larger than the conversion ball.

• Non-circulating version with retained trip ball is available for high angle applications.

Differential Fill Float Collar - Model 443 • Differential fill valves are similar to the auto-fill valves in that their main purpose is to fill the casing while running into the wellbore from the annulus. • The result is a reduction in surge pressure while running the casing by taking a large part of the displaced mud inside the casing instead of outside. • The valve controls mud influx into the casing and prevents over-filling.

• The lower valve is made of cast iron for extended durability. It is not PDC drilliable. • The shoe version of this equipment (not shown) is the 343 and both can be converted with one ball. • The model 350 and 450 utilize aluminum differential fill valve components.

• Conversion from differential fill to a conventional flapper valve is accomplished by pumping a 2" zinc alloy ball releasing a sleeve that holds back a spring-loaded flapper. Once converted, the equipment is standard float equipment. • PDC drillable versions are the Model 450 Differential Fill Float Collar and the Model 350 Differential Fill Float Shoe.


Special Collars


Landing Collar - Model 502 • Landing collars are usually box by pin subs

run in the casing or liner string to act as a point on which to land a set of casing wiper plugs.

• Consisting primarily of a shell

and concrete molded with a flat profile for landing standard plugs. There are no valves for holding back pressure.

Landing Collar with Non-Rotating Landing Plates - Model 502P • A landing collar on which casing or hanger wiper

plugs land, but in this case the plugs must include non-rotating teeth.

Landing Collar with Non-Rotating Landing Plate and Ball Catcher - Model 507P • This is the basic 502 but features a ball catcher

inside the orifice.

• The 502, 502P, and the 507P

are PDC drillable.

• The ball catcher can be set up to hold the ball

until a predetermined pressure is reached. After ball seat conversion the ball is trapped and fluid is permitted to freely bypass

Orifice Collar for Tieback Strings - Model 402OG • The OG (Orifice Groove) Collar features the

proven Sure-Seal 3™ Valve with a designed leak path.

• The OG equipment acts as an Auto-Fill valve when running the tie back assembly.


• The 402OG has the same base

components of a 402. Therefore it is completely PDC drillable and can be set up to run with either a standard or non-rotating plug.

• The 402OG releases trapped fluid when stinging in the tie back.



Weatherford's stab-in equipment is designed for cementing large diameter casing strings through tubing or drill pipe. It virtually eliminates the problem of cement contamination, prevents drilling out large quantities of cement associated with the use of large size cementing plugs, and provides greater accuracy in slurry displacement. Also, large amounts of excess cement is not left on the sea floor, which makes it a more environmentally friendly system for cementing.

Stab-In Arrangement Weatherford has provided inner-string cementing equipment to the industry for over 30 years. Our system provides the necessary tools to accomplish cementing using any one of several methods. Weatherford’s innerstring equipment is designed with the float shoe or collar having a tapered concrete top. The taper guides the drill pipe adapter into the shoe or collar receiver. Two systems are available from Weatherford for use in innerstring cementing. The stab-in and the screwin systems can be provided in virtually any size casing in which drill pipe can be run. With the stab-in, no rotation is required to engage or disengage the tool from the inner-string adapter. The operator simply lowers the drill pipe with the stinger on the end into the receptacle and slacks off approximately 20,000 lbs (or whatever amount is necessary to offset pump off forces) to maintain a fluid tight connection.

Model 154 - Stab-in Stinger

For inner-string cementing through a shoe, a double valve assembly is preferred. The screw-in system allows the inner-string adapter to connect the float equipment to the casing while reciprocating. This style is commonly used when running scab-liners. The screw-in stinger is engaged with left hand rotation and released with right hand rotation. Inner-string cementing is designed to save the operator rig time and cement costs, while improving cementing hydraulics. Weatherford can provide service with a trained technician and a full complement of handling tools such as the drill pipe spider, base plate, and pack-off head, all packaged in a compact offshore transportation box.

Model 155 - Screw-in Stinger




Single Valve Stab-In Collar - Model 402-1 The Stab-In Float Shoe (Model 303-1) and the StabIn Float Collar (Model 402-1) feature.

• PDC drillable once the stinger and drill pipe are removed

• A Sure-Seal 3™ valve proven superior in flow endurance.

• Available in various valve types.

• A tapered cement top and smooth phenolic bore receptacle which facilitates stab-in operations.

• Uses Stab-in stinger Model 154

Single Valve Stab-In Collar with Latch-In Plug - Model 402-1L • The Float Shoe (Model 303-1L) and Float Collar (Model 402-1L) have the same features as Model 402-1, but with the addition of a latchin drill pipe wiper plug.

This tool features: • Latch-in drill pipe wiper plug. • Positive bump on displacement with the plug. • Latching in of the wiper plug, which acts as back-up to the valve and again is PDC drillable. • Uses stab-in stinger Model 154.

Screw-In (Duplex) Float Collar - Model 481 • The Model 481 Float Collar can be run with a Model 303 Float Shoe or any of the regular float shoes and guide shoes.

• Back-out requires rotation to right.

• Stinger has coarse left hand threads.

• Used in running scab-liner.

• Positive lock between stinger and float equipment.

• Uses screw-in stinger Models 155 or 155RD.

• Prevents pump-off pressures acting on drill pipe.

Double Valve Stab-In Downjet Float Shoe with Latch-In Plug - Model 323-2L • Basic difference in this version is that the shoe/collar comes with two Sure-Seal 3 Valves for added security.

• The latch-in receptacle is aluminum to allow it to hold more back pressure while the stinger receptacle is phenolic.

• This configuration features the double valve, stab-in inner string, and latch-in drill pipe dart all in one package.

• All components are PDC drillable.


Insert Float Equipment


Insert Float Valve - Model 1111 • Has an easily drilled cast aluminum flapper valve. • Threads available for STC or LTC couplings (STC must be specified for 8 5/8", 24 lb/ft casing).

• Can be run alone or in combination with a float collar, float shoe or guide shoe. • Serves as a landing point for a casing wiper plug.

Auto-fill Insert Float Valve - Model 1112 • Has an easily drilled cast aluminum flapper float valve that is held open by a plastic orifice fill tube that controls filling of casing while running in.

• The 1111, 1112, and the 1005 can be drilled with PDC bits.

• Assembly threads into coupling. • Equipment is converted with a high density trip ball which is dropped from surface.

Baffle Plate - Model 1005 • A cast aluminum plate for threading or slipping into a coupled connection.

• Also available in Bakelite (Model 1007).

• Serves as an economical plug stop.

Latch-In Plug and Baffle - Model 1013 • Latch-in top plug with cast iron nose and threaded cast iron receptacle which allows the casing to fill automatically. • Also available in an aluminum nose and receptacle version (Model 1014).

• The 1013 and 1013F are not PDC drillable while the 1014 and 1014F can be drilled with a PDC bit.

Latch-In Flex Plug & Baffle - Model 1013F • A flexible latch-in plug with cast iron nose and threaded cast iron receptacle.

• Available with aluminum nose and receptacle (Model 1014F).

• A latch-in plug that latches into the receptacle for a positive seal in both directions.



Tubing & Small Float Equipment

Tubing Float Shoe - Model 302 V and Tubing Float Collar - Model 401V • The unique patented* vortex design allows maximum possible flow areas through the valve components minimizing fluid velocity and resulting erosion damage. • A passageway through the retainer cup draws the ball into a contoured cup that guides the ball to the center when flow is initiated downward. • Flow is directed away from the ball and creates a low-pressure area to secure the ball and prevent hammering. • A rubber-coated phenolic ball seats rapidly with reverse flow even in water and high deviations. • An aluminum seat and ball retainer are securely threaded and sealed to the collar and shoe. • The collar and shoe withstand high temperatures, pressures, and extended circulation. • They exceed API RP10F Category III flow endurance and pressure test requirements.

Circulating Hydronaut™ Shoe - Model 364VR • Provides controlled automatic fill of tubing. • Permits circulation without conversion if needed.

• A bridging ball prior to cementing converts the shoe to conventional float equipment. • Available in 2 7/8" and 3 1/2" sizes.

* U.S. Patent No. 4,945,947


MudMasterTM System


One of the primary concerns while running casing is the possibility of formation damage. In critical and close tolerance casing running both fracture pressure and pore pressure must be carefully managed. A delicate balance exists that can be disturbed if casing is not run properly. When pipe is run into the hole mud must be displaced. Surge pressure is created by this fluid movement during pipe run-in operations and needs to be reduced to maintain formation integrity. The only acceptable way to reduce this pressure is to lower the fluid velocity in the annulus by moving the mud up the inside of the casing as the path of least resistance. This also keeps potentially destructive cuttings inside the filter shoe where they cannot block off the annulus. The Weatherford MudMaster System was designed originally for use in deep water cementing applications where surge pressures were caused by rapid lowering of large diameter casing into the wellbore. It acts as a downhole mud cleaner and its advantages over standard auto-fill float equipment are numerous: • Large auto-fill areas (4" equivalent ID) reduce the surge pressure and allow increases in the casing running speed. • Filter Shoe Joint keeps casing internals contaminant-free by preventing debris from entering the casing string during run-in. • Self-cleaning Landing Collar allows Stabilizing Plug to latch in, creating a barrier separating the cement from the displaced fluids. These components can withstand high bump and back pressures.

• Small diameter Drill Pipe Dart allows the same dart to be used with a wide range of drill pipe and casing running components with no adjustments. • Complete MudMaster System is PDC drillable.



MudMaster Filter Shoe The Weatherford System is designed for use in critical environments where surge pressure and well debris are factors. This patented component of the MudMaster System provides unique advantages over casing strings equipped with conventional auto-fill or differential-fill equipment. The filter shoe is the first line of defense in assuring successful cementing operations. In conventional auto-fill scenarios cuttings, carvings, and debris are swept into the casing string as the mud fills the pipe. This debris is known to have contributed to valve, seat, plug, stage tool and liner failures for many years but became an even larger problem in the deep-water market. This unique shoe track design allows the mud to freely flow through screens with very large cumulative flow areas while trapping potentially damaging contaminants in the shoe track joint. Surge pressures are reduced with an innovative nose designed to allow maximum flow areas. In sizes 10 ¾" and larger there is no restriction under 12.56 in2 from the casing bottom to the drill pipe or liner hanger. This increased flow area reduces surge pressures and thus increases maximum allowable running speed. The MudMaster Filter Shoe Joint can arrive at your well site as a fully made up shoe track and eliminates time making up float equipment. This component is fully PDC drillable and compatible with most liner, subsea and full string casing accessories. Available in 26, 40 and 80 feet increments, the pipe used to build the filter shoe is supplied by the customer or can be provided by Weatherford.

Benefits • Provides surge reduction. • Prevents mud losses. • Reduces incidents caused by debris influx. • Saves rig time. • PDC drillable. • Increases casing running speed. • Simple - no activation required.


MudMasterTM Filter Shoe Joint



In many deepwater applications, the casing strings are extremely restricted for annular space. It is common practice to under-ream the hole past the previous shoe to improve casing running cementing operations. Weatherford designed the patented Centralizer Sub to address the difficult issue of providing stand-off in under-reamed sections. Combining the centralizer sub and float valves provide improved economics and place a centralizer near the critical shoe area.

Centralizer Sub Float Shoe with Composite Eccentric Nose - Model 543WM • This tool features a welded centralizer mounted in a recessed groove on the outer sub body. • Versions are available that allow casing rotation. • The shoe configuration is designed with an eccentric composite nose. The jets are most often set as down-jets. • The entire system is PDC drillable and rated to API RP I0F, III-C. • The valve is cemented in most cases. Other versions with different valve types are available such as auto-fill or differential-fill. • The eccentric nose allows the casing to be run or rotated past troublesome ledges. • Centralizer Subs also available with Float Valves.



Bow Spring Centralizer Sub with Composite Concentric Nose Guide Shoe - Model 549WN • Same design as a sub, without the valve. • The nose is concentric, showing the possibilities for various combinations with a modular system. This is often driven by customer preference and experience. • Jets are most commonly upjet.

Bow Spring Centralizer Subs - Model 541 • Built from matched grade steel and threads to match customer’s casing or liner string. • Centralizers Subs are engineered to match casing specifications while maintaining internal diameters. • The centralizer is always pulled regardless of the direction of pipe movement. • Rotation not recommended with standard model. • Centralizer Subs can be run in holes with as little as 0.125” diametric clearance. • Model 541R available for casing rotation.





Stage Tool - Model 751E Weatherford’s patented EliminatorTM heavy duty multiple stage cementing tools are unparalleled in the industry for successful stage cementing with minimum cost. No other stage cementing equipment boasts such an impressive list of advantages:

• Compact, simple design. • Single unitary sleeve both opens and closes the tool. • No pressure traps. • Clear surface indications of opening and closing. • Superior strength due to unitary sleeve design resulting in greater wall thickness and reduced O.D.’s as compared to other designs. • Aluminum Seats - the seats are made of an easily drilled aluminum material. • Unique mechanism prevents premature closing. • Locking and anti-rotation devices. • Special application plugs and cancellation cones available. • Special seals available for H2S, CO2 and geothermal applications. • No premature openings due to annular restrictions or pressure buildups. The Eliminator Stage Tool product series is available for twostage (Model 751E), three-stage (Model 752E), and PDC drillable configurations (Model 751 PDC or 752 PDC).

TOOL SIZE

OPENING PRESSURE (psi)

CLOSING PRESSURE (psi)

3 1/2" thru 5 1/2"

700 -- 1000

1500

6 5/8" thru 10 3/4"

700 -- 1000

1200

11 3/4" thru 13 3/8"

700 -- 1000

1000

16" thru 20"

400 -- 700

800




Features: • Sizes 4 ½" through 9 5/8" standard N80 8-Round tools are furnished with LTC box and STC pin connections. Sizes 4 ½" through 9 5/8" L-80 & P110 and heavy weight N80 8-Round tools are furnished with LTC box and pin connections. Sizes 10 ¾" through 20" 8-Round tools in all grades are furnished with STC box and pin connections. • EliminatorTM stage cementing tools with non-standard sizes, ratings, threads and special clearance outside diameters are available on special order. • Premium threaded Eliminator stage cementing tools may be equipped with box subs as well as pin subs. • A Model 752E stage cementing tool is positioned below a Model 751E stage cementing tool in a threestage cementing job. Model 751E two-stage cementing tools are color-coded red. Model 752E three-stage cementing tools as well as their opening and closing plug sets are color-coded blue. • The Model 751E stage tool can be run and is compatible with most annular casing packers.




Stage Tool - Model 754HO Hydraulic Opening Multiple Stage Cementing Tool Weatherford has many tools to assist the completion and drilling engineer in achieving a successful primary cementation in wellbores with inclinations of 60 to 90 degrees or in well conditions that are not conducive to free-fall opening plugs. The Model 754HO offers several distinct advantages over competitive tools such as:

• Hydraulic Operation - the opening process requires no free-fall plug device; therefore, it is not dependent upon hole angle or mud properties for operation. • Can be run in conjunction with most liners when combined with a special set of closing plugs. • This tool is compatible for use with single or multiple casing packers. • Aluminum Seats - the seats are made of an easily drilled aluminum material that requires little or no torque to drill up. While a specific PDC drillable hydraulic stage tool (754 PDC) is also available with special plugs, most 754HO Stage tools are PDC drillable. • Back-Up Opening System - where annular pressure limitations do not allow hydraulic operations of the tool, it can be operated with either the free-fall plugs or pump down plug system. • One Piece Inner Sleeve - the high strength steel, unitary seal-off sleeve is a one-piece construction which is not exposed to obstructions that may be encountered in the annulus. • Quality Construction - the engineering safety factors built into this tool make it extremely reliable. It has an extensive track record from fields all over the world.




Key Features: • Hydraulically opened with internal casing pressure - saves rig time waiting on free-fall plugs. • After closing, no pressure imbalance exists that would allow the tool to open. • Elimination of the free fall plug means faster drillouts. • Opening pressure is adjustable on the rig site to meet hydraulic conditions of each individual well. • Tool is based on proven technology for locking devices and sealing sleeve. • Integral box connection on most threads with no welding to give extremely high body strength. • Available in sizes 2 7/8 through 20”. • Single unitary sleeve design allows reduced OD and increased ID dimensions, which opens up other configuration possibilities such as casing packers. Anti-rotation features on seats and closing plugs speed drill-out times.

The Model 754 Hydraulic Stage tools are shipped with all shear screws in place. The opening pressure is easily adjustable in the field to precisely match operational requirements by the operator, cementer, or a trained Weatherford field technician. Operational limits, dimensions, and procedures for all stage tools are included in every shipping crate. Close tolerance, H2S resistant, and PDC drillable stage tools for liner hanger systems available upon request.


Stage Tools Accessories


ACCESSORIES All 751 EliminatorTM two-stage tools are furnished with first-stage plug, 751E free-fall opening cone and 751E closing plug, unless otherwise specified. All 752E three-stage tools are furnished with 752E free-fall opening cone (color blue) and 752E flexible closing plug (color blue), unless otherwise specified. Optional plug sets available: • 751E-2C for pump-down opening or continuous two-stage cementing consists of bypass plug and 751E pump-down opening plug. • 751E-2B for two-plug first stage system, consists of bypass plug and shut-off plug and baffle. • 752E-3C for three-stage, pump-down opening or continuous lower stage cementing consists of bypass plug and 752E pump-down opening plug (color blue). • 751E-2D for two-stage cancellation cone (color black).



Liner Accessories

Hydraulic Tools PDC Model 854 Liner Hanger Plug Set The 854 plug set is a patented design set of plugs based on the Weatherford SSR™ collet system. They were engineered to allow the operator to run a high quality plug system with liner hangers, activated through the use of wiper darts instead of balls. The plug set allows the operator to bump up the lower plug and hydraulically open a Model 754PD stage tool (and casing packers if required), then perform a model second stage cement job. When finished, a second dart is used to displace the cement and launch the closing plug.

LipStick™ Guide Shoe Weatherford has developed a Free Rotating Eccentric Guide Shoe to run casing in difficult holes. The allplastic nose shoe is designed to rotate to the spot of the least resistance without rotating the casing. The mudflow through the center of the shoe will in many cases reduce the obstruction and the casing can pass. In other cases it may save a cleaning trip prior to running the casing. The rotational feature will guide casing through the doglegs and highly deviated segments of the hole. The shoe is built on a box end collar, therefore compatible with the casing string. The phenolic material is easy to drill with any kind of bit.

Applications • To save a cleaning or wiper trip, or work casing past known ledges. • Beneficial for deviated holes, doglegs and holes with unstable formations.


• Can be run in conjunction with liner hangers, packers, sand screens or a combination thereof.

Pack-Off Stage Tools


Model 781E Pack-Off Stage Tool (POSTTM)) System Weatherford has designed the Eliminator™ based Pack-Off Stage Tool (POST) for specific applications. Typically these are where weak formations are encountered or in areas, such as above a slotted liner, where cement can be detrimental to the production formation. The Eliminator POST System is a combination of the 751E stage tool with an integral casing packer. The Eliminator POST and the standard Eliminator Stage Tools use the same plug systems.

Features and Benefits • The packer on the Eliminator Pack-Off Stage Tool is capable of holding up to 4,000 psi differential when properly inflated with drilling fluids. • The packer on the POST System gives a weight indication when the packer sets. • The POST System can be run in horizontal wells above the top of a slotted liner when a pump down opening plug is used. A number of packer lengths can be selected for the POST System, including a 4-foot standard length rib packer or a 10-foot rib packer. • The POST System uses the cementing ports for inflation; therefore, only one set of holes needs to be isolated with the closing sleeve. • The POST System features an externally adjustable inflation pressure that can be set at the well site prior to going in the hole. • The POST System features a sliding sleeve that will fully open all cementing ports, in contrast to a single port provided with a rupture disk tool. • The POST System can be run as a two-stage or three-stage tool.

NOTE: The POST System has a larger OD than a standard stage tool to allow for the secondary opening sleeve. Therefore, the nominal hole ID the tool will be run in should be a minimum of 3/8" (.375") larger than the OD of the tool.



Cement Wiper Plugs

Weatherford has developed a new generation of Standard and Non-Rotating Cementing Plugs to drill out faster and to meet the increasingly stringent conditions of deeper and higher pressure drilling. These high technology plugs are designed to provide the industry's highest performance levels when used in conjunction with the WiperLok® System. The plugs maintain separation of cementing fluids, wipe casing walls clean, and prevent cement contamination. When bumped against a float collar, they provide positive indication of displacement and casing integrity.

Standard Cementing Plugs • High-grade design for compatibility with all types of float equipment.

• PDC and insert bit drillable materials featuring a Duromer core.

• Temperature rating of 150°C/300°F • Secondary sealing and wiping fin on both top and bottom plugs. • Polyurethane fins for superior casing wiping and abrasion resistance.

WiperLock™ Non-Rotating Cementing Plugs • The same easy-to-drill high temperature properties of the Standard Plugs. • A one-piece core with an innovative non-rotational device allowing the plugs to mate in any casing inclination with the Weatherford non-rotating float equipment.


• A core design and proprietary materials allow easy drill-out with PDC and insert bits. • Weatherford also has tapered plugs for most casing combinations of two or three strings in either the standard or non-rotational type. These plugs feature a single core and are uniquely molded into one unit.



SSR™ Cementing Plug System The Sub-Surface Release (SSR) Cementing Plug System provides compactness, reliability and simplicity in cementing operations. It incorporates an adaptation of the field-proven cementing plugs and is comprised of four parts - double dart plug container, swivel equalizer, non-rotating sub-surface plugs with drill pipe wiper darts and a non-rotating float collar. The plug containers that Weatherford have developed and offer have been customer driven. Plug container offerings are matched to well and customer requirements and range from the TDH to the remote control canister heads.

TDH Top Drive Cementing Manifold Weatherford's cementing manifolds are used for cementing liners or casing strings which require dart launching capability. Weatherford's TDH Top Drive Cementing Manifold is the premium cementing manifold in the oil and gas industry. The TDH is engineered to release one or two drill pipe darts and a setting ball. The TDH cementing manifold features an indicator that positively indicates proper launching of the drill pipe darts. The TDH Top Drive Cementing Manifold has withstood the test of many harsh applications in the North Sea and the deepwaters of the Gulf of Mexico. It has been the cementing manifold of choice for many major operators when cementing liners or long casing strings.

Key Benefits • Compact design with integral ball release, swivel, and indicator sub. • Ability to release one or two drill pipe darts. • Dart release on the fly; no need to stop pumping. • Tensile rating over 1 million pounds, working pressure 7,500 psi.

Application The TDH Top Drive Cementing Manifold can be used any time a liner or casing string is being landed with a drill pipe string. This includes casing long-strings that are landed sub-sea. The TDH can be used with topdrive or rotary-drive drilling rigs.

* Nodeco is a registered trademark in Norway and New Community only




SSR Liner Wiper Plug - Model 836BC Liner wiper plugs are typically run during cement jobs for indication of cement displacement, as a casing wiper, and as a barrier at the cement/displacement fluid interface. The field-proven SSR™ plugs are now available with a liner setting seat which eliminates the requirement for an additional landing collar. SSR Liner Wiper Plugs have been successfully deployed in many harsh applications in the North Sea and Gulf of Mexico. SSR Liner wiper plugs are available for casing sizes 8 5/8” and larger. Darts are available for drill pipe sizes 4-1/2" through 6-5/8". SSR plugs feature the one-piece core with an innovative non-rotational device allowing the plugs to mate in any casing inclination. Weatherford also has tapered plugs for most casing combinations of two or three strings in either the standard or non-rotational type.

BENEFITS • Field proven collet release system. • Urethane construction makes for quick and easy drill-out, saving time and money. Used with cement-filled non-rotating landing or float collar to ensure efficient drill-out of shoe track. • The 836 BL SSR Liner wiper plug is a top plug only system with an integral ball seat. This eliminates the need for the ball seat in the landing collar and reduces open hole surge pressures. • The SSR plug is the liner wiper plug of choice on liners 8 5/8" and larger. Its construction eliminates drill-out problems that are sometimes experienced in these sizes. Available in single (top plug) systems only.


ReamerShoe™ Tools


The ReamerShoe Tools These products are designed to run on all sizes of casing or liners. In the event wellbore restrictions or ledges are encountered, a ReamerShoe will provide the operator the means to open the wellbore or move down past a ledge. The new DiamondBack® ReamerShoe System operates effectively in either rotating or reciprocating applications.

Features • Full coverage Tungsten Carbide cutting structure in diamond shaped pads. • Large flow directed ports cover the entire wellbore while rotating and reaming and prevent channeling when pumping cement. • The aluminum eccentric nose is easily drillable and features Weatherford’s chip breaking technology. This prevents the bit balling that sometimes occurs when drilling aluminum. • Internal nose designed for fast drill-out with PDC or Tricone bits. • Integral (milled in) spiral stabilizer blades should be coordinated with the centralizer profiles to provide clearance for rigid centralizers. • Robust Ledgerider™ nose profile allows easy rotation past ledges or obstructions while running pipe. • Sizes available from 2 7/8" to 20" or other special combinations. • Compatible with all casing and liner hanger assemblies. Best, however, when run with the Weatherford Nodeco®* rotating liner hangers. • Backreaming feature allows casing to be reamed down or back should casing have to be pulled out.




Centralizers

Weatherford has a full line of mechanical cementing products especially designed to meet your requirements for primary cementing. Weatherford is unique in that we offer both conventional Welded as well as Non-weld designs in both spring bow and rigid designs. Currently Weatherford offers many variations, all of which can be found in our Mechanical Cementing Products brochure in more detail or through your local Weatherford representative. Here is a quick review of the primary products dealing with casing centralization.

Welded S Series Centralizer These welded centralizers meet or exceed API requirements. There are eight basic highstrength bows available in various sizes to make up any casing/open hole combination. End collars are available in latch-on or slipon versions.

Features include: • Rigid end band design with strengthening ribs to prevent deformation. • Integral hinge that once installed around the casing will not unhinge even under extreme conditions.

• Self-locking safety hinge pins. • Installation over a stop collar or casing collar.

Non-Weld Centralizer The Weatherford Non-Weld Centralizer is a high quality product that has been used in the field for more than 25 years. It exceeds API 10D standards and its design has several distinct features: • All non-weld bow combinations can be field-assembled to reduce shipping costs. • The non-weld end collars feature heavy gauge steel with extra strong hinges.


• Five basic bow designs. • Each bow is secured in place with a patented locking tab. Each bow has uniform bow hardness without localized hardening.

Centralizers For Horizontal Application


The number of horizontal wells is steadily rising as operators realize the increased production advantages of these wells. One of the most difficult problems when running casing into horizontal wells is the drag created by the friction between the casing string and the wellbore. A careful balance must be created between the running, starting, and restoring forces. Weatherford has a variety of products proven to perform well in horizontal conditions.

SpiraGlider™ Centralizer System • The SpiraGlider was specifically designed for high angle and horizontal wells and is ideal for use with reciprocating or rotating liner hangers. The system consists of a low friction steel centralizer and two asymmetrically beveled stop collars that reduce drag while running into conventional wellbores. • The centralizer’s unique design combines excellent wear resistance over other cast material centralizers with optimized mechanical flow enhancement and a large bypass area. • The unique fin design provides positive stand-off and resists high side loads yet will yield at a predetermined force to allow passage through restricted holes.

SpiraGlider™ HD Centralizer The HD is the newest addition to our horizontal product line. Its steel blades have an extremely low coefficient of friction and improve mud removal by providing mechanical flow enhancement. The design permits the positive centralizer to collapse in an undergauge hole.

STT-1-SL This centralizer is designed specifically for horizontal applications. Its bows are configured so that the moving force is kept low while the excellent restoring force gives optimum standoff. The centralizer assists in the free rotation of the casing or liner.


2002 Float Equipment Catalog

Centralizers For Horizontal Application

LoTORQ™ Centralizer This roller centralizer is based on the idea of putting rollers as the contact points between not only the centralizer and the formation, but also between the centralizer and the casing OD. This allows the operator to reduce drag while running in the well and also to reduce torque while rotating the pipe during cementation. The benefits of pipe rotation during cementation have been known for many years but only within the last few years have these benefits been available to all operators. Record strings of 7" liners past 32,000 ft MD have been rotated with these tools.

LoDRAG™ Centralizer This drag reduction centralizer is based on patented Weatherford technology. The axial rollers, secured by rigid blades, provide standoff while reducing drag when running or pulling casing.

Tandem Rise™ Centralizer This Non-Weld Centralizer has a double curvature on the bow spring. It features outstanding restoring force with a very low moving force. Its design allows it to ride through areas where the hole ID is slightly under-gauge.

Centralizer Subs The Centralizer sub is a combination tool that is a centralizer built onto a collar. In the spring bow versions the body is grooved to allow the centralizer to fit flush with the OD of the tool. The grooves serve the primary purpose of pulling the centralizer into or out of the wellbore so that it does not end up in compression. In the rigid bow versions the blades are machined from the OD of the collar stock.


Special Tools for Horzontal Applications

Centralizers for Horizontal Applications Weatherford offers a wide variety of centralizer products for all applications. In horizontal wells much of the selection process is based on well geometry and the issues of bypass area, bucking and the balance between stand-off and friction. Each well condition may require a specific tool or combination of tools to maximize the opportunity for casing running and cementing success. Application engineers are available in every major region around the world to assist in centralizer selection and placement using advanced computer modeling. Call the extreme well specialists at Weatherford to assist in your next casing design. Float Equipment for Horizontal Applications High quality, reliable float equipment is a critical component of the cementing products package. High angle wells are often difficult to clean and can require additional circulation time. Weatherford’s team has tested its equipment for circulation periods over 100 hours and at rates up to 1,000 gpm. Weatherford's standard Sure-Seal 3™ valves excel in flow durability and reliability. The spring-loaded cone system make this equipment the industry's first choice for horizontal applications. Sure-Seal 3 Float Shoe can be ordered in upjet or downjet configurations to deliver a jetting action around the critical shoe joint. The Sure-Seal 3 valve is also available in the BBL™ ReamerShoe™ Tool.

With the new tighter restrictions that have come into play over the past years, surge reduction and simply getting the casing to total depth without losing large amounts of drilling fluids are major issues. Weatherford has responded by forming a whole new product line built around the MudMaster™ System. The purpose of the MudMaster System is to allow most of the displaced mud from running casing to auto-fill directly into the casing string instead of having to take the flow path of the annulus, which would result in higher back pressures and ultimately lost circulation. Some restrictions that we are successfully running casing through today include 13-3/8" x 16”, 11-3/4" x 13-3/8", 9-5/8" x 11-3/4" and the 7-5/8" x 9-5/8" sizes.


The heart of the MudMaster System is a new large bore float collar known as the L42 series. There are several versions of this valve that allow the system to work with any wellbore from vertical to horizontal. If contaminated mud or poorly cleaned wellbores is a problem the system can add a filter shoe. The MudMaster Filter Shoe allows the removal and trapping of debris before it enters the casing valves during auto-fill. This prevents debris from affecting the performance of cementing plugs, liner hangers, or diverter tools. Weatherford's proven anti-rotation mechanism will withstand long circulation periods and provide quick drillout. The high strength polyurethane plugs will withstand up to 80% of casing burst pressure for most casing weights and grades. When you need equipment for high angle wells, look to the reliability specialists at Weatherford.

Service One of the most important aspects of good primary cementation in high angle wellbores is planning. It cannot be emphasized enough as to the importance of having an experienced team that can plan your casing centralization, float and stage equipment, casing running procedures and tools. As geometry, tolerances, pressures, and temperatures become more difficult, it becomes increasingly important to match equipment to application. Weatherford has specialists available around the world who are able to assist with your application engineering. We are ready to assist where needed in your tubular make-up, running, cementing, and completion requirements of horizontal and vertical wells.



Special tools for Horzontal Applications

LoTAD™ ROLLER TOOL

DIVERTER TOOL NODECO® LINER HANGER

RIGID CENTRALIZER

NON-WELD CENTRALIZER

LoDRAG™ CENTRALIZER

SPIRAGLIDER™ (HD) CENTRALIZER TANDEM RISE™ CENTRALIZER STAGE TOOL

CENTRALIZER SUB

DIAMONDBACK® REAMERSHOE™TOOL



CHARTS AND DIMENSIONS

2002 Float Equipment Catalog

Guide Shoe, Sure Seal 3™ Float Shoe & Float Collar Dimensions


PRESSURE RATINGS FOR STANDARD FLOAT EQUIPMENT

1. Sure-Seal 3™ Float Collars meet API RP10F Category III C requirements. ®

2. Wiperlok Urethane Plug maximum temperature rating: 250°F, 300°F Limited Service. 3. Maximum back pressure applied should not exceed 80% of the collapse pressure rating of the casing. 4. Internal and external pressure applied should not exceed connection leak resistance and pressure rating of the casing. 5. Bump Pressure ratings may be lower if debris prevents sealing between the plugs and the float collar. 6. 9- 5/8” WiperLok urethane plugs are limited to 5,000 psi bump pressure. 7. 9- 5/8” WiperLok Nitrile plugs are limited to 8,000 psi bump pressure @ 270°F, 6,000psi @ 300°F, 5,000psi @ 350°F. 8. Ratings for Model 402P applies to Model 502P and Model 507P.


WORLDWIDE CUSTOMER SERVICE 515 Post Oak Blvd. · Houston, Texas 77027 Phone: (713) 693-4000 · Fax (713)693-4300 www.weatherford.com

[email protected]

Weatherford products and services are subject to Weatherford's standard terms and conditions. For more information concerning the full line of Weatherford products and services, please contact your authorized Weatherford representative. Unless noted otherwise, trademarks and service names noted herein are the property of Weatherford.

Brochure # 67.01

Mechanical Cementation Products

The Weatherford Technique For the last half century, the industry has depended on Weatherford to provide quality equipment for its primary cementing needs. Weatherford now offers the world's largest and most complete line of cementing products not just a partial solution. As the recognized specialists in the field, Weatherford provides the broadest product offering, innovative tool designs, the latest in manufacturing technology, combined with the backing of experienced engineers to analyze the well and make detailed recommendations for satisfying your cementation objectives. From the beginning of the cementing job to its conclusion, Weatherford provides complete assistance to make sure that job runs properly. Weatherford strives to provide customers with the lowest cementing costs possible. That's the Weatherford technique.

After job completion, Weatherford engineers evaluate the performance data of the well and, by comparing it with other similar cementations, can help customers prepare for future cementing jobs. Product Testing Weatherford technicians regularly perform destructive tests to assure that Weatherford products continue to meet the highest standards, exceeding even those of the American Petroleum Institute. Weatherford commitment to the industry involves providing efficient products to meet real well conditions. Weatherford's main manufacturing plants are licensed to use the API monogram.

CentraPro Plus™ Software Program The mechanical cementing products installation pattern, as part of the total cementing program, should be based on individual well conditions and operating objectives. To assist in developing the most effective program for a well, Weatherford has developed the CentraPro Plus program, a sophisticated lateral load software program designed to provide optimum deployment of cementation products in the well. This innovative program utilizes three dimensional analysis to calculate the lateral forces as well as hookload calculations. Engineering Weatherford's experienced cementing engineers are available worldwide to help ensure the correct implementation of the cemention program and the proper installation of each piece of equipment. The on-site engineers continually monitor the well and can quickly adapt the program to unforeseen conditions. Weatherford's cementing engineers at the wellsite.

1

Weatherford's specially-designed test procedures monitor products under abnormal conditions.

CONTENTS Welded Centralizers Non-Weld Centralizers SpiraGlider Centralizers Centralizers (non-weld) Centralizers (welded) Flow Enhancement Tools Roller Centralizers Stop Collars Specialty Tools Installation Patterns

2 (inside cover) 3 (inside cover) 4 5 9 14 15 16 17 19

WELDED CENTRALIZERS API SPECIFICATION centralizers are manufactured for all common casing/hole size combinations... assurance that Weatherford centralizers are of a consistently high quality.

RIGID QUALITY CONTROL TESTS are performed on every centralizer to verify size and fit.

ROLL-FORMED RIDGE around end collars provide extra rigidity, minimizes out-of-round distortion in shipping or storage, and makes a streamlined leading edge to prevent hanging up.

INTEGRAL HINGES have eight sections and seven shear points for maximum load capacity. Hinges wrap to the inside, against the casing, for optimum design strength. PREMIUM BOW SPRINGS of high quality spring steel undergo special heat treatment to achieve maximum centering power and minimum running resistance. HINGE PINS embody a self-locking design that will not work loose, yet they tap easily into place. SUPER-STRONG WELDS and maximum weld length are the product of Weatherford’s patented automatic welding equipment. Assuring ultimate strength and uniformity in every weld. For Excellent Performance Under Tensile Stress Weatherford welded centralizers have been providing excellent service for over 50 years. They are the result of high quality materials, coupled with the most advanced manufacturing processes, including proprietary robotics technology and automatic centralizer welding. Consistency is foremost in Weatherford’s goal of assuring performance excellence at the wellsite. Special high strength steel springs are made to design specifications. End collars are uniquely designed with integral hinges and self-locking hinge pins. The centralizer ribs are engineered to maintain rigidity while providing a streamlined profile in the wellbore. Testing centralizers for stress confirms that they will run under demanding conditions without distortion or destruction.

2

NON-WELD CENTRALIZERS EXTENDED PROFILE Prevents bows from hitting against casing collar. HIGH QUALITY BOWS Uniform bow hardness.

FIELD ASSEMBLY All bow combinations can be field assembled to reduce shipping costs.

EXCEEDS THE REQUIREMENTS OF API SPECIFICATION 10D With exceptional starting and restoring performance. CHOICE OF BOWS Weatherford offers five basic designs with additional configurations available. The bows can be made in stainless steel and in sizes to match any well profile.

END COLLARS Non-weld models feature heavy gauge steel with extra strong hinges. HINGES Turned inward for maximum strength. SELF LOCKING HINGE PIN For easy and sure

installation. For Excellent Performance While Under Compression

*U.S. Patent Number 4,077,470

3

LOCKING TAB Each bow locks in place securely with patented tab.* More than 50 years experience has gone into the design, manufacture and continual improvement of the Weatherford non-weld centralizers. Weatherford’s newest generation of products reflects that experience. They are built for use in the most demanding conditions. Starting with the uniformity of the bow hardness to the heavy gauge end collars, they provide a ruggedness for just about any application. These premium products exceed the requirements for API Specification 10D. Testing centralizers for compression assures that the centralizers can withstand very high forces when running casing. The test, illustrated at left, shows that a damaged centralizer will still remain intact under severe conditions.

SPIRAGLIDER™ Highly Deviated And Horizontal Well Centralizer System*

OPTIMIZED HYDRODYNAMICS AND FLOW-BY AREA Hydrodynamic shape of spiral fins allows optimal mud displacement and minimal pressure drop across centralizer. Induced vortex flows enable superior mud removal.

STEEL CONSTRUCTION The SpiraGlider system is made of steel, giving it a toughness advantage over other materials and alloys.

SHAPED TO MINIMIZE RUNNING RESISTANCE Both spiral and straight fin designs minimize drag forces while running pipe. The fins glide smoothly on the low side of horizontal boreholes.

PRE-DEFINED FIN LOAD RESISTANCE SpiraGlider fin design resists high sideloads, yet are engineered to intentionally yield at predetermined sideforce under stuck-pipe conditions. UNIQUE STOP COLLARS Provide protection for the centralizer’s leading edge and performs as a positioning device.

SMOOTH SURFACE Wide symmetrical fins are smoothly beveled on both ends to have lower coefficient of friction and to ease casing movement in either direction. Typical Average Coefficient of Friction** 0.12 **Valid for water/bentonite, water/chalk and oil base mud, accord-ing to a study by the Institute of Tribology, Technical University of Clausthal, Germany

0.10 0.08 0.06 0.04 0.02 0.00

■ Zinc

■ Steel

The Weatherford SpiraGlider centralizers are the newest innovations in a broad offering of cementation products. They were designed specifically for highly deviated or horizontal wells and are ideal for use with liner hangers. The SpiraGlider system consists of a STEEL centralizer and two asymmetrically-beveled stop collars.The SpiraGlider centralizer’s unique design features allow them to run in restricted holes while yielding reduced wear and a low coefficient of friction for minimal drag. They promote optimal mud displacement during cementation, utilizing fins that create a vortex motion for superior mud removal. The SpiraGlider construction is tough and gives maximum standoff and wear resistance. *patents pending

4

NON-WELD CENTRALIZERS STA 0

STRAIGHT BOW CENTRALIZERS

STA 1

STA 3

STA 3

STA 4

Weatherford’s non-weld straight centralizers are the result of more than 50 years of field experience and laboratory testing. This newest design has features making them ideal for both tubing and casing applications. • Non-weld design eliminates weak spots. • Choice of standard bow heights assures optimum starting/restoring force criteria. • Patented locking tabs hold bows in the collars. • High-quality, spring-steel bows and specially designed collar hinges provide reliable downhole performance. • Available in stainless steel.

Non-Weld Straight Centralizer

5

Bow Type in.

Maximum O.D. mm

Min Compressed O.D. in. mm

Standard Bow Heights

Non-Weld Straight Centralizer Bow Heights

STA0 Weatherford markets straight centralizer bows in several standard sizes and provides a variety of bow In. 0.965 configurations for special applications. If your well mm 24.5 plan requires a special design, contact your local Weatherford representative. Non-Weld Straight Centralizers Casing Size (in.)

Centralizer Bow Configurations

Casing Size (in.)

STA1

STA2

STA3

STA4

1.161

1.437

2.303

3.051

29.5

36.5

58.5

77.5

Bow Type in.

Maximum O.D. mm

Min Compressed O.D. in. mm

4"

ST A0 ST A1 ST A2 ST A3 ST A4

6.186 6.579 7.131 8.902 10.398

157.1 167.1 181.1 226.1 264.1

4.965 5.201 5.201 5.201 5.201

126.1 132.1 132.1 132.1 132.1

10 3/4"


13.010 13.404 13.955 15.727 17.223

330.5 340.5 354.5 399.5 437.5

11.790 12.026 12.026 12.026 12.026

299.5 305.5 305.5 305.5 305.5

4 1/2"


6.691 7.084 7.636 9.407 10.903

169.9 179.9 193.9 238.9 276.9

5.470 5.706 5.706 5.706 5.706

138.9 144.9 144.9 144.9 144.9

11 3/4"


14.023 14.417 14.968 16.739 18.235

356.2 366.2 380.2 425.2 463.2

12.802 13.039 13.039 13.039 13.039

352.2 331.2 331.2 331.2 331.2

5"


7.196 7.589 8.141 9.912 11.408

182.8 192.8 206.8 251.8 289.8

5.975 6.211 6.211 6.211 6.211

151.8 157.8 157.8 157.8 157.8

13 3/8"


15.668 16.062 16.613 18.385 19.881

398.0 408.0 422.0 467.0 505.0

14.448 14.684 14.684 14.684 14.684

367.0 373.0 373.0 373.0 373.0

5 1/2"


7.701 8.094 8.646 10.417 11.913

195.6 205.6 219.6 264.6 302.6

6.480 6.716 6.716 6.716 6.716

164.6 170.6 170.6 170.6 170.6

16"


18.326 18.720 19.271 21.043 22.539

465.5 475.5 489.5 534.5 572.5

17.106 17.342 17.342 17.342 17.342

434.5 440.5 440.5 440.5 440.5

6 5/8"


8.837 9.231 9.782 11.553 13.050

224.5 234.5 248.5 293.5 331.5

7.616 7.853 7.853 7.853 7.853

193. 199. 199. 199.5 199.5

18 5/8"


20.984 21.377 21.929 23.700 25.196

533.0 543.0 557.0 602.0 640.0

19.763 20.000 20.000 20.000 20.000

502.0 508.0 508.0 508.0 508.0

7"


9.216 9.609 10.161 11.932 13.428

234.1 244.1 258.1 303.1 341.1

7.995 8.231 8.231 8.231 8.231

203.1 209.1 209.1 209.1 209.1

20"


22.376 22.770 23.321 25.093 26.589

568.4 578.4 592.4 637.4 675.4

21.156 21.392 21.392 21.392 21.392

537.4 543.4 543.4 543.4 543.4

7 5/8"


9.847 10.241 10.792 12.563 14.060

250.1 260.1 274.1 319.1 357.1

8.626 8.863 8.863 8.863 8.863

219.1 225.1 225.1 225.1 225.1

24"


26.426 26.820 27.371 29.143 30.639

671.2 681.2 695.2 740.2 778.2

25.206 25.442 25.442 25.442 25.442

640.2 646.2 646.2 646.2 646.2

8 5/8"


10.857 11.251 11.802 13.573 15.070

275.8 285.8 299.8 344.8 382.8

9.636 9.873 9.873 9.873 9.873

244.8 250.8 250.8 250.8 250.8

26"


28.451 28.845 29.396 31.168 32.664

722.7 732.7 746.7 791.7 829.7

27.231 27.467 27.467 27.467 27.467

691.7 697.7 697.7 697.7 697.7

9 5/8"


11.867 12.261 12.812 14.583 16.080

301.4 311.4 325.4 370.4 408.4

10.646 10.883 10.883 10.883 10.883

270.4 276.4 276.4 276.4 276.4

30"


32.501 32.895 33.446 35.218 36.714

825.5 835.5 849.5 894.5 932.5

31.281 31.517 31.517 31.517 31.517

794.5 800.5 800.5 800.5 800.5

NON-WELD CENTRALIZERS TANDEM RISE™ BOW CENTRALIZERS This special design increases the ratio of restoring force to moving force. It has the ability to withstand high lateral loads encountered in horizontal holes. The non-weld design increases its ability to withstand compressive loading while running in the wellbore. It is available for close tolerance applications and can be installed over casing couplings and stop collars. . Benefits include: • Better standoff for increased mud removal • Reduced drag while running pipe • Reduced wall sticking for easier pipe movement • Increased contact area for less bow penetration into the formation • Complete mud removal while cementing

Tandem Rise Bow Profiles Bow Spring "X" Number Bow Thickness

“X" Bow Height

“Z" Max. Coupling Length Based on Coupling 1" Above Casing Size

in.

mm

in.

mm

in.

TR1

.171

4.35

.800

20.32

358.8*

TR2

.171

4.35

1.171 29.74

14 1/8* 14 1/8"

mm

TR3

.171

4.35

1.421 36.09

358.8

TR4

.171

4.35

2.171 55.14

14 1/8" 14 1/8"

358.8

358.8

*Based on 5/8" clearance for coupling NOTE: 1) All bows 1 ½" (38.1 mm) wide

Non-weld Straight Centralizers – Tubing Tubing centralizers can be effective in tubingless completions, for guiding and stabbing tubing into downhole equipment or in reducing frictional drag in deviated holes. They can also be used to center wireline tools, to protect control lines and cables, or to prevent wear on tubing and casing due to thermal expansion and contraction. For optimum tubing concentricity, Weatherford recommends the use of positive tubing centralizers inside casing.

Non-weld Straight Centralizers – Tubing

Size (in.)

Maximum Bow OD (in. mm) 5 1/8” 130

Minimum Compressed Bow OD (in. mm) 3 3/8” 86

5 1/2” 7 1/4”

140 184

3 1/2” 3 1/2”

89

STTIII STTIV

8 1/2”

216

3 1/2”

89

STTI

5 5/8”

143

3 7/8”

STTII

6

153

4

Bow Type STTI

2 3/8"

TR 1

2 7 /8"

TR 2 3 1 /2"

TR 3 TR 4

STTII

89

98 102

STTIII

7 3/4”

197

4

102

STTIV

9

229

4

102

STTI

6 1/4” 6 5/8”

159

4 1/2”

114

169

117

213

4 5/8” 4 5/8”

245

4 5/8”

117

STTII STTIII STTIV

8 3/8” 9 5/8”

117

* When bows are completely compressed, these figures represent the centralizer’s largest rigid diameter presented by the bow, the hinge or any other part. NOTE: STI AND STII centralizers should not be installed over any casing collar or stop collar.

6

NON-WELD CENTRALIZERS BOW SPRING CENTRALIZERS BOW SPRING CENTRALIZER SUB

The Bow Spring Centralizer Sub meets the demands of ultra-tight clearance casing strings. Where special drilling requirements demand that casing be run in previous casing or open hole with close tolerances, this tool allows passing very tight restrictions, followed by expansion into an under reamed hole. The Bow Spring Centralizer Sub offers numerous advantages, including:

Casing* Size

Previous Casing Min. Drift ID

4.500” 5.000” 5.500” 7.000” 7.625” 8.625” 9.625” 10.750” 11.750” 13.375”

• Combines slim hole capabilities with proven Weatherford welded centralizer • Runs inside ultra-tight clearances • Centralizer bows recess completely into tool body then expands for casing centering in open or under reamed sections • Allows maximum fluid bypass area to minimize the impact on circulating pressure

5.000” 5.500” 6.000” 7.500” 8.125” 9.125” 10.125” 11.250” 12.250” 14.000”

Open Hole Size 53/4”—97/8” 6”—105/8” 61/2”—105/8” 77/8”—121/4 81/2”—121/4” 95/8”—131/2” 101/2”—143/4” 121/4—151/2” 131/2”—16” 143/4”—171/2”

Number of Bow Springs 4 4 4 4 6 6 6 6 6 8

U.S. Patent No. 5,575,333 *Special Tools Available 16” - 24”

Bow Spring Centralizer SUB*

POSITIVE CENTRALIZERS Weatherford’s non-weld positive centralizers are available for both tubing and casing applications. They significantly reduce frictional drag when used in deviated holes, and can provide nearly 100 percent standoff (concentricity) when run inside a cased hole. Concentric casing strings facilitate liner and packer positioning, stage cementing, surface cementing, slip and packoff installation, and well-abandonment. Weatherford’s non-weld positive centralizers offer the following features: • Non-weld design eliminates weak (brittle) spots passage. • Patented locking tabs hold bows in the collars • Large selection of bow sizes. Non-Weld Positive Centralizer

Non-Weld Positive Centralizers – Casing

Size (In) 4 4 1/2 5 5 1/2 6 5/8 7

Bow Type/Maximum Box OD” PO1 (in) (mm)

PO2 (in) (mm)

PO3 (in) (mm)

PO4 (in) (mm)

5 1/8 130.2 5 5/8 142.9 6 1/8 155.6

5 1/2 139.7

5 7/8 149.2 6 3/8 161.9 6 7/8 174.6

6 1/8 155.6 6 5/8 168.3 7 1/8 181.0

6 5/8 168.3 7 3/4 196.9 8 1/8 206.4

7

7 3/8 187.3 8 1/2 215.9 8 7/8 225.4

7 5/8 193.7 8 3/4 222.3 9 1/8 231.8

9 1/2 241.3 10 1/2 266.7 11 1/2 292.1

9 3/4 247.7 10 3/4 273.1 11 3/4 298.5

12 5/8 320.7 13 5/8 346.1 15 1/4 387.4

12 7/8 327.0 13 7/8 352.4 15 1/2 393.7

17 7/8 454.0 20 1/2 520.7 21 7/8 555.6

18 1/8 460.4 20 3/4 527.1 22 1/8 562.0

25 7/8 657.2

26 1/8 663.6

7 5 /8 8 5 /8

8 3/4 222.3 9 3/4 247.7 9 5 /8 10 3/4 273.1 10 3/4 11 7/8 301.6 11 3/4 12 7/8 327.0 13 3/8 14 1/2 368.3 16 17 1/8 435.0 18 5/8 19 3/4 501.7 20 24

7

• U-profile bow design permits maximum fluid • Available with solid bows. • Can be transported unassembled to reduce shipping costs.

21 1/8 536.6 25 1/8 638.2

6

152.4

6 1/2 165.1 177.8

8 1/8 206.4 8 1/2 215.9 9 1/8 231.8 10 1/8 257.2 11 1/8 282.6 12 1/4 311.2 13 1/4 336.6 14 7/8 377.8 17 1/2 444.5 20 1/8 511.2 21 1/2 546.1 25 1/2 647.7

(in)

PO5 (mm)

6 1/8 165.1 7

203.2

7 1/2 190.5

(in)

PO6 (mm)

PO7 (mm)

6 7/8 174.6 7 3/8 187.3 7 7/8 200.0

7 1/4 184.2 7 3/4 196.9 81/4 209.6 8 3/4 222.3 9 7/8 250.8 10 1/4 260.4

228.6

8 3/8 212.7

9 1/8 231.8 9 1/2 241.3 10 1/8 257.2

9 1/2 241.3 9 7/8 250.8 10 1/2 266.7

11 1/8 282.6 12 1/8 308.0 13 1/4 336.6

11 1/2 292.1 12 1/2 317.5 13 5/8 346.1

14 1/4 362.0 15 7/8 403.2 18 1/2 469.9

14 5/8 371.5 16 1/4 412.8 18 7/8 479.4

21 1/8 538.8 22 1/2 571.5 26 1/2 673.1

21 1/2 546.1 22 7/8 581.0

8

(in)

27

711.2

10 7/8 276.2 11 7/8 301.6 12 7/8 327.0 14

381.0

15

406.4

18 5/8 422.3 19 1/4 489.0 21 7/8 555.6 23 1/4 590.6 27 3/8 695.3

PO9 (mm)

PO10 (in) (mm)

7 5/8 183.7 8 1/8 206.4 8 5/8 219.1

8 7 /8 225.4 9 3 /8 238.1 9 7 /8 250.8

10 3/8 263.5 10 7/8 276.2 11 3/8 288.9

5 7/8 149.2 6 3/8 161.9 6 7/8 174.6

9 1/8 231.6

10 3 /8 263.5 11 1 /2 292.1 11 7 /8 301.6

11 7/8 301.6

7 3/8 187.9 8 1/2 215.9 8 7/8 225.4

12 1 /2 317.5 13 1 /2 342.9 14 1 /2 368.3

14

381.0

9 1/2 241.3

15

406.4

16

431.8

457.2

15 1 /2 393.7 16 1 /2 419.1 18 1 /4 463.6

17 1/8 435.0 18 1/8 460.4 19 3/4 501.7

10 1/2 266.7 11 1/2 292.1 12 5/8 320.7

19 5/8 496.6 22 3/8 568.3 23 3/4 603.3

20 7 /8 530.2 23 1 /2 596.9 24 7 /8 631.8

22 3/8 568.3 25 1/8 638.2 26 1/2 673.1

27 3/4 704.9

28 7 /8 733.4

30 1/2 774.7

(in)

PO8 (mm)

10 1/4 260.4 10 5/8 269.9 11 1/4 285.8 12 1/4 311.2 13 1/4 338.6 14 3/8 365.1 15 3/8 390.5 17

(in)

13

355.6

13 3/8 339.7

PO11 (in) (mm)

13 5/8 346.1 15 1/4 387.4 17 7/8 454.0 20 1/2 520.7 21 7/8 555.6 25 7/8 657.2

NON-WELD CENTRALIZERS BOW SPRING SELECTION GUIDE NON-WELD CENTRALIZERS Casing Size (In.)

Bow Type

Preferred Casing Hole Size Size Combination (in.) (in.)

Bow Type

Preferred Hole Size Combination (In.)

4”


— — 65/8” — —

103/4”

ST AO ST A1 ST A2 ST A3 ST A4

121/4” 121/4” 125/8” 131/2” 143/4” 151/2”

41/2”


6” 61/8” 61/4” 61/2” 63/4” — 81/2” 83/4” 97/8” 105/8”

113/4”


— — 131/2” 143/4” 151/2” 171/2”

5”


61/4” 61/2” 63/4” — 81/2” 83/4” 105/8” 11”

133/8”


— 143/4” 151/2” 16” 171/2”

ST A0 ST A1 ST A2 ST A3

65/8” 6 1/2” 63/4”

ST AO ST A1 ST A2 ST A3

171/2” — 181/2” 181/2”

ST A4

20” 22”

51/2”

16”

ST A4

— 71/8” 83/8” 81/2” 83/4” 97/8” 105/8” 11”

61/2”


77/8” 81/2” 85/8” 85/8” 83/4” 105/8” 11” 121/4”

185/8”


— — — 22” 24”

7”


83/8” 81/2”

20”


— — 22” — 24” 26”

81/2” 8 5/8” 83/4” 81/2” 8 5/8” 83/4”

105/8” 11” 121/4”

75/8”


— 91/2” 97/8” 121/4” 131/2”

24”


— — 26” — 28”

85/8”


93/4” 97/8” 105/8” — 121/4” 131/2”

26”


— — — — 30” 32”

ST A0 ST A1 ST A2 ST A3

— 11” 113/8” 113/4” 121/4” 121/2” 125/8” 143/4” 151/2”

30”


— — — 32” 34” 36”

95/8”

ST A4

Centralizers for other casing and hole combinations available upon request.Chart does not apply to BowSpring Centralizers Subs

CENTRALIZER SELECTION To select the right product for application, basic considerations need to be examined. To help achieve the proper balance between starting force and restoring force, Weatherford offers centralizers with a wide range of bow heights and shapes as well as one piece aluminum rigid centralizers for deviated and horizontal wells. Starting Force and Moving (= Running) Force Test according to API SPEC 10D

F<

F = Measured Starting and Running ( = Moving) Force W = Weight of 40 feet medium weight casing

The starting force is the maximum force required to start a centralizer into previously run casing. It should be less than the weight of 40 feet (12.2 meters) of medium weight casing.

Restoring Force Test According to API SPEC 10D Restoring Force

Test Positions

The restoring force is the force exerted by a centralizer against the casing to keep it away from the bore hole wall. Current API Specification 10D states that "67% may or may not be sufficient for a good cementation." Practical experience has shown that standoff values of 75 to 90% are adequate, even in horizontal wells.

8

WELDED CENTRALIZERS S-SERIES CENTRALIZERS The Weatherford S-Series centralizer is the standard welded centralizer for casing-hole size combinations and is a high quality welded product that meets or exceeds API Specification 10D requirements. It offers a choice of six different bow heights, available for any casing/open hole configuration. The end collars are available as latch-on or slip-on. The S-Series features: • Rigid Design - End bands are equipped with ribs to provide rigidity to the bands. Bow springs are of high quality heattreated spring steel. • Integral Hinge - Folded to the inside of the endbands so that, once installed, it won't unfold even under extreme conditions. • Self-Locking Hinge Pins - Equipped with a positive safety locking device. • Clearance - Since bow springs are attached to the O.D. of the end collars, the centralizers may be installed over stop collars or casing collars. Product Number: S110 _ _ Latch-On. Available bow springs: 25, 30, 36, 46, 57 and 85.

B-SERIES CENTRALIZERS Some hole conditions do not require the same superior performance characteristics of the S-Series. In these instances, the B-Series centralizers offer an economical alternative. They are manufactured in a broad range of hole sizes and may be installed over the casing collars or stop collars. Product Number: B110 _ _ Latch-On Available bow springs: 25, 36 and 46.

SINGLE LINER CENTRALIZERS These centralizers are specifically designed for close tolerance applications where running drag must be minimal, yet the centering strength as high as possible. The uniquely-shaped bows accomplish this most effectively, making these centralizers the optimum solution. • Available in Turbolizer styles • Available as latch-on or slip-on • Notched or lap-welded versions available • Furnished with integral set screws • Can be installed without set screws, between stop collars, for casing rotation. Product Numbers: : :

9

11216 Latch-on with lap-welded bows. 12212 Latch-on with notched-bows 12312 Slip-on with notched-in bows

WELDED CENTRALIZERS TURBOLIZER™ CENTRALIZERS Weatherford Turbolizer centralizers have all of the characteristics of regular centralizers as far as starting and restoring forces are concerned. The main difference is that the Turbolizer centralizers have a built-in stop collar and deflector blades. These blades, or fins, deflect the fluid flow in a turbulent and outward directed spiral.

The Turbolizer centralizer's fluid motion causes: • Break up of cement and drilling fluids channeling • Deflection of mud and cement toward washed-out sections of the well bore • Improved filter cake removal • Self-cleaning action which prevents the turbolizers from "balling-up”

SINGLE STRAIGHT (TURBOLIZER) CENTRALIZERS • Choice of bow spring and deflector fin sizes • Equipped with right or left handed fins • Have integral set screws • Meet API Specification 10D requirements in most casing and hole combinations • Fins are heat treated spring steel • Have built-in stop collar on leading edge* DOUBLE REVERSE BOW TURBOLIZER CENTRALIZERS • Greater centering efficiency • 360º wall coverage for increased load bearing area • Lower starting force • Available with integral stops • Turbolizer fins on only one end so they can be installed over stop collars

ROTATING CENTRALIZERS (MODEL STT-1SL) Rotating centralizers were developed in response to industry requirements for centralizers that could be used with a rotating liner in highly deviated conditions. These centralizers offer the following features: • High restoring force for optimum standoff • Low moving force to minimize drag • Allow free rotation of the pipe for maximum displacement efficiency • Over stop collar design minimizes moving forces while reciprocating • Meet or exceed API Specification 10D requirements *Note: Single straight Turbolizer centralizers should never be installed over stop collars, any upset connections or over a casing collars.

10

WELDED CENTRALIZERS RIGID CENTRALIZERS, LATCH-ON These centralizers provide positive standoff and centering, and can be used in both cased or open hole applications. In cased hole situations, they can be installed below casing hanging equipment and under liner hangers to facilitate proper setting. They offer: • Single bar or double bar — Single bar versions are recommended for cased hole applications; double bar for open hole. • Available in various configurations — Available in latch-on or slip-on versions and also in latch-on with integral stops.

RIGID T-BAR CENTRALIZERS These centralizers are custom built to suit severe service applications such as in subsea conditions and in large bore deviated holes where extreme axial and radial loads may be encountered. Either a T-bar or flat bar may be used to provide a large bearing surface to virtually eliminate well bore gouging. Options may include: • • • •

Extra heavy-duty end collars Double rows of set screws Flat bar or T-bar staves Bronze cladding on stave ends to protect wellhead equipment

THERMAL STABILIZERS (NOT SHOWN) Thermal stabilizers are used to insulate steam injection lines from the casing. The rigid stabilizers, with replaceable nonasbestos-compound insulation pads affixed to the bows, greatly reduce heat loss.

SPRIAL-TYPE MT CENTRALIZERS These centralizers are designed for use with multiple tubing strings (dual, triple, etc., or tubingless completions) run in one hole. The centralizers may be installed over close tolerance stop collars.

11

WELDED CENTRALIZERS GRAVEL PACK CENTRALIZERS These centralizers are designed to give a minimal amount of drag resistance when passing through the previous casing or wellhead and then spring out to fit underreamed sections and washouts. • Useful in sections where gravel packing is being implemented • Used for oversized holes • Available with special clearance collars designed to go through restrictions

DEPTH ORIENTATION MARKERS (DOM)™ Weatherford Depth Orientation Markers are patented* devices which exert a focused magnetic field inside the casing so that they will affect the casing collar locator tool and provide a downhole reference point. • Used on flush joint pipe where connections are hard to detect • Used with non-magnetic tubulars in corrosive service • Provide a permanent benchmark on wells for future production • Made to match specific casing weights • Offered in standard and close tolerance versions • Will sometimes save a gamma ray run *U.S. Patent number 4,244,424

MICRO-ANNULUS SEALS (CEMENT SEAL UNITS) Weatherford micro-annulus seals are used to block off possible gas or fluid migration along the casing-cement interface. This product offers the following features: • Reduce interzonal communications • Prevent gas pressure on the annulus • Deter leakage of stimulation media up the annulus • Minimize gas storage well leakage • Decrease loss of injection media in injection wells • Standard model is rated to 275°F (135°C) • High temperature model rated to 400°F (204°C)

12

WELDED CENTRALIZERS BOW SPRING SELECTION GUIDE — WELDED CENTRALIZERS Hole Size (in.)

2 3/8

2 7/8

3 1/2

4 1/2

4 1/2-4 3/4

30

*16

*12

—

5 3/4-6

36

30

25

6 1/8-6 3/8

46

30/36

6 1/2-6 3/4

46

7 3/8-7 7/8 8 3/8-8 5 /8 8 3/4-9 9 1/2-10

5 1/2

5

6 5 /8

7

7 5/8

8 5/8

Casing Size (in inches)

95/8

10 3 /4

11 3/4

13 3/8

16

18 5/8

20

—

—

—

—

—

—

—

—

—

—

—

—

—

*12/16

*12

—

—

—

—

—

—

—

—

—

—

—

—

30

*16

*12/16

—

—

—

—

—

—

—

—

—

—

—

—

46

36

25

*16

*12

—

—

—

—

—

—

—

—

—

—

—

57

46

46

36

30/36

25

*12

—

—

—

—

—

—

—

—

—

—

57

57

46

36/46

36

30/36

*16/25

*16

*12

—

—

—

—

—

—

—

—

85

57

57

46

46

36

25

25

*12

—

—

—

—

—

—

—

—

85

85

85

57

46/57

46

36

36

25/30

—

—

—

—

—

—

—

—

85

85

57/85

57

57

46

46

36

25/30

*12/16

—

—

—

—

—

—

10 5/8-11

—

12-12 1/4

—

—

85

85

85

85

57

57

57

46

36

25

—

—

—

—

—

14-15 1/2

—

—

—

—

85

85

85

85

85

57/85

46/57

46

36/46

—

—

—

—

17-18 5/8

85

57

25/36

—

—

—

—

—

—

—

—

—

—

—

85

85

191 /2 -201/2 —

46

—

—

—

—

—

—

—

—

—

—

—

—

—

57

—

—

22-23

—

—

—

—

—

—

—

—

—

—

—

—

—

—

85

46/57

46

24

—

—

—

—

—

—

—

—

—

—

—

—

—

—

—

57

46/57

26

—

—

—

—

—

—

—

—

—

—

—

—

—

—

—

85

57/85

Notes: *1. Close Tolerance — Integral Stop-Collar *2. Where two bow spring sizes are indicated, the lower should be used for smaller hole sizes or with light weight casing and 2 centraliers per joint installations. *3. Type 12 and 16 bow springs are identical, 12 is for notched-in, 16 for lap-welded Close Tolerance Centralizer

WELDED CENTRALIZER SPECIFICATIONS Casing Size In.

13

12 Bow Max. Min. Bow Comp. O.D. O.D. In. in.

16 Bow Max. Min. Bow Comp. O.D. O.D. in. in.






85 Bow Max. Min Bow Comp. O.D. O.D. in. in.

4 1 /2

6.000

5.500

6.250

5.500

7.250

5.500

7.550

5.500

8.500

5.500

9.250

5.500

11.500

5.500

14.500

5

6.500

6.000

6.750

6.000

7.875

6.000

8.250

6.000

8.750

6.000

9.750

6.000

12.000

6.000

15.000

6.000

5 1 /2 6 5 /8

7.000

6.500

7.250

6.500

8.375

6.500

8.750

6.500

9.125

6.500

10.250

6.500

12.500

6.500

15.500

6.500

8.125

7.625

8.375

7.625

9.500

7.625

9.875

7.625

10.375

7.625

11.375

7.625

13.625

7.625

16.625

7.625

7 75/8

8.500

8.000

8.750

8.000

9.875

8.000

10.250

8.000

10.750

8.000

11.750

8.000

14.000

8.000

17.000

8.000

9.125

8.625

9.375

8.625

10.500

8.625

11.000

8.625

11.500

8.625

12.375

8.625

14.625

8.625

17.625

8.625

8 5 /8 9 5 /8

10.250

9.625

10.500

9.625

11.500

9.625

12.000

9.625

12.500

9.625

13.875

9.625

15.625

9.625

18.625

9.625

11.250 10.750

11.500

10.750

12.500

10.750

13.000

10.750

13.500 10.750

14.875 10.750

16.625 10.750

19.625

10.750

10 3/4 11 3/4

12.375 11.875

12.625

11.875

13.625

11.875

14.125

11.875

14.625 11.875

15.875 11.875

17.750 11.875

20.875

11.875

13.375 12.875

13.625

12.875

14.625

12.875

15.125

12.875

15.625 12.875

16.875 12.875

18.750 12.875

21.875

12.875

13 3/8

15.000 14.500

15.250

14.500

16.250

14.500

16.750

14.500

17.250 14.500

18.750 14.500

20.375 14.500

23.500

14.500

16

17.625 17.125

17.875

17.125

18.875

17.125

19.375

17.125

19.875 17.125

21.375 17.125

23.000 17.125

26.125

17.125

18 5/8

20.250 19.750

20.500

19.750

21.500

19.750

22.000

19.750

22.500 19.750

24.000 19.750

25.625 19.750

28.750

19.750

20

21.625 21.125

21.875

21.125

22.875

21.125

23.375

21.125

23.875 21.125

25.375 21.125

27.000 21.125

30.125

21.125

5.500

ROLLER CENTRALIZERS LoDRAG™ CENTRALIZER

LoDRAG™

The LoDRAG centralizer is also a mechanical frictionreduction system that performs independently of drilling or completion mud film strength or lubricity. The small contact area of the rollers with the casing or borehole wall functions exceptionally well in underpressured conditions, where risk of differential sticking is high. LoDRAG tools have been used primarily to run casing and sand-control screens into unconsolidated sandstone reservoirs. Using LoDRAG tools in these reservoirs can reduce axial drag by up to 60 percent. The LoDRAG tool can reduce axial friction in cased holes by similar percentages. The features of the LoDRAG centralizer include: • Rollers help to avoid plowing that can create major drag problems • Precision machined inside diameter provides excellent rotational performance in mud • Small roller contact area reduces differential sticking • Rollers provide exceptional wear resistance • Torque-reducing performance improves the cement sheath • The roller/axle relationship ensures that axle shear stresses remain within elastic limits • High quality construction materials improve highpressure / high-temperature capabilities

LoTORQ™ CENTRALIZERS The majority of LoTORQ tools have been used in extendedreach wells to run and rotate long, heavy-wall liners where rotation provides an optimum cement sheath. Weatherford developed a mechanical friction (torque and drag) reduction system that performs independently from drilling/completion fluids. Analysis has shown that the small contact area of the rollers function exceptionally well in under-pressured conditions where the risk of differential sticking is high. The LoTORQ centralizers offers operators the same benefits as the LoDRAG centralizer but also serves well when long and/or heavy cemented liners are being rotated.

The LoDRAG tools achieve optimum performance when: • Casing, liner, and screens are being run into horizontal and extended-reach wells • Centralizer wear may compromise the cement job • Where HSE requirements ban the use of oil-based and pseudo-oilbased mud • Underpressured formations may cause differential sticking

LoTORQ™

14

FLOW ENHANCEMENT TOOLS RIGID CENTRALIZERS Weatherford's broad offering of flow enhancement tools perform well in highly deviated and horizontal wells. They are designed in many sizes, materials and configurations to meet customer requirements, even under severe conditions.

The rigid centralizers are generally constructed in one piece to add greater strength and are held in place by high load stop collars or set screws. The tools are designed to improve cement flow while promoting maximum standoff from the bore hole. SPIRAL RIGID CENTRALIZERS • Blades overlap the entire 360º open hole circumference • Reduced flow area between the spiral provides a vortex motion for increased fluid velocity • Extra length gives maximum centralization • Spiral design provides optimum flow area • Made of high strength, corrosion-resistant cast aluminum • Used with corrosion-resistant alloys (CRA) to negate ionic transfer SHORT SPIRAL RIGID CENTRALIZERS • Spiral blades increase annular turbulence • Blades are set at an average of 45º for maximum fluid swirl • Blades and collar made of abrasion-resistant mild steel • Continuous welds secure blades to collars • Available with or without set screws SPIRAGLIDER™ CENTRALIZERS • Designed specifically for highly deviated and horizontal wells • Ideal for use with liner hangers • Steel construction provides superior toughness over other materials and alloys • Fin design provides low coefficient of friction to reduce drag forces while running pipe • Fins create vortex flow to optimize mud displacement and minimize pressure drop across the centralizer • SpiraGlider construction gives maximum standoff • Fin design resists high sideloads • Spiral blades yield to allow passage through unexpected undergauge open hole

Now Available in a Heavy Duty Version

15

STOP COLLARS J10H STOP COLLARS Weatherford stop collars limit the movement of mechanical cementing products on the pipe and are manufactured to withstand high axial forces. Four standard designs are available.

This stop collar is for use on casing up to 30 inches in diameter. A single row of set screws offers good gripping force and cost effectiveness.

Model J10H Stop Collar (60200)

JSH STOP COLLARS This hinged stop collar has an internal groove into which a spiral locking pin is driven, firmly wedging the collar into position around the casing. The JSH Stop Collar is used on both upset and non-upset casing and provides maximum annular clearance.

J10S STOP COLLARS Superb solid collar set-screw device gives excellent gripping force, and used where high axial loads are expected

Model J10S Stop Collar (60300)

Model JSH Stop Collar (60900)

Stop Collars Size (in.)

J5H STOP COLLARS

JSH

2 3/8

Collar Type/Maximum OD (in. mm) J5H J4H J10H/J10S 3 3 /8 86

2 7/8

The J5H Stop Collar has a cross-bolt design that makes installation quick and easy. This economical collar can be used where annular tolerances are not critical.

3 1/2 4 1/2 5 5 1/2 6 5/8 7 7 5/8 8 5/8 9 5/8 10 3/4 11 3 /4 13 3/8

Model J5H Stop Collar (60500

5 5/8 143 6 1/2 156 6 5/8 168

4 3/4 5 3/4 6 1/4 6 3/4 7 7/8

121

3 7 /8 4 1 /2

98 114

146

5 5 /8 143

159

6 1 /8 156 6 5 /8 168 7 3 /4 197

171

7 3/4 197 8 1/4 209 8 7/8 225

8 1/4 8 7/8

225

9 7/8 251 10 7/8 276

9 7/8 10 7/8

276

8 1 /4 209 8 7 /8 225 9 7 /8 251 10 7 /8 276

12

305

12

305

12

305

13

330

13

330

13

330

14 5/8 17 1/2

371 445

14 5 /8 371 17 1 /2 445 20 1 /8 511

21 1/2

546

14 5/8 371

16 18 5/8

200 210 251

26

21 1 /2 546 25 1 /2 648 27 5 /8 701

30

31 7 /8 810

20 24

*Other sizes are available.

16

SPECIALTY TOOLS WILDCAT™ SCRATCHER Weatherford’s Wildcat™ scratchers remove excessive wall cake and improve the cement bond between the casing and porous formations while reinforcing the cement column. Their hinged design makes them easy to install. For running in the hole, a series of scratchers is mounted on the casing string. The inclined external bristles abrade the wellbore during running and reciprocation. The scratchers feature large fluid-bypass slots and coiled bristles for bending durability.

Wildcat (51007)

RECIPROCATING WELLBORE WIPERS These wipers remove excess wall cake to improve cement-to-formation bonding by producing a wiping action during running and reciprocation. A continuous, interlocking and overlapping loop of tempered-steel wire cable is laced into the hinged collars. A bolt holds the wipers in position and eliminates the need for stop collars. A hinged version is also available. Reciprocating Wellbore Wiper

Wellbore Wipers ROTATING WELLBORE WIPERS (MODEL 54850) Rotating wellbore wipers can be used when well conditions do not permit reciprocation of the casing string, but do permit rotation. The 60-inch long strips are clamped tightly to the casing at intervals along the length of the wiper. Note: Stop collars must be used with rotating wellbore wipers.

Product Number

Casing Size

5360041

4 ½” 5 ½”

11 1/8” 12 1/8”

5360070

7”

13 5/8”

346

5360075 5360085

7 5/8” 8 5/8”

14 1/4” 15 1/4”

5360095

9 5/8”

16 1/4”

5360010

10 3/4”

5360013

13 3/8”

5360051

Other sizes upon request.

17

Loop O.D. in. mm.

Compressed O.D. in. Mm 5 5/8” 6 5/8”

143

206

362

8 1/8” 8 3/4”

387

10 3/4”

248

413

9 3/4”

273

17 3/8”

441

20”

508

11 7/8” 14 ½”

368

283 308

168

222

302

SPECIALTY TOOLS PLUG-BACK STINGERS Weatherford offers for rent or sale full length joints of 6.5 lb/ft. 2 7/8" EUE 8rd N-80 tubing fully dressed with appropriate centralizers and cable scratchers. This configuration is effective with rotation and/or reciprocation, depending on hole conditions and rig capabilities. The centralizing and abrading action that the "Plug-Back Stingers" provide greatly improves the mud displacement efficiency of the cement slurry. The small diameter stinger minimizes the possibility of mud contamination in the slurry as it is withdrawn from the plugged interval and provides a "weak" point in the drill string should problems cause the pipe to be cemented in. Weatherford has been renting 2 7/8" tubing dressed to set cement for over 20 years on the Gulf Coast. This service is now available from your local Weatherford representative. Tubing will come pre-dressed with hinged rotating centralizers and scratchers. The entire string usually consisting of 10, 20, or 30 joints is racked and safely stored in baskets. Additional components that are available include the drill pipe wiper darts, up-jetted diverter sub, and handling tools. Handling tools can include a TS100 Spider, base plate and elevators. Crossovers and extensions are available as needed. CEMENT BASKETS (SOLID OR HINGED) Weatherford cement baskets protect weak formations from excessive hydrostatic pressure exerted by the weight of the cementing column. They are normally installed on the casing string above the weak formations, but they are also used in stage-cementing or in cementing the annulus from the surface. Each basket’s overlapping metal fins provide maximum flexibility and fluid passage while maintaining optimum support characteristics. Weatherford’s hinged baskets can be installed on upset pipe and can be disassembled for shipping and space economy. Special sizes upon request.

“Plug-Back Stingers" provide greatly improves the mud displacement efficiency of the cement slurry.

STANDARD CEMENT BASKET SPECIFICATIONS CSG./ TBG. Size. 3 ½"

Latch-on Type —

4 ½" 5 ½"

—

No. of Bows

Slip-On Type

No. of Bows

Total Length

Basket O.D.

—

1835731

10

—

1835741

10

24 ½" 24 ½"

11 ½"" 12 ½"

Min. Hole Size 5" 6"

1825751

12

1835751

12

24 ½"

13 ½""

7" 7 5/8" 8 5/8"

1825770

14

1835770

14

1825775

14

1835775

15

24 ½" 24 ½"

15" 15 5/8"

1825785

16

1835785

16

24 ½" 24 ½"

16 5/8" 17 5/8"

10 5 /8" 11 5 /8"

24 ½" 24 ½"

18 3/4" 19 3/4"

12 3 /4" 13 3 /4"

24 ½" 24 ½"

3 21 /8"

15 ½"

24 26 5/8"

18" 20 5/8”

28"

22"

9 5/8"

1825795

18

1835795

18

10 3/4" 11 3/4"

1825710

18

1835710

19

1825711

20

1835711

21

13 3/8"

1825713

24

1835713

24

16" 18 5/8"

1825716

28

1835716

28

1825718

34

1835718

34

20"

1825720

34

1825720

34

24 ½" 24 ½”

7 1/4" 8 3 /4" 9 ½"

Cement baskets should be installed over stop collars to facilitate pipe reciprocation.

18

RECOMMENDED INSTALLATION PATTERNS Choosing proper installation pattern for mechanical cementing products is essential to achieving desired results. For example, centralizers should be installed between stop collars in close-tolerance situations to avoid drag caused by increased starting forces. So contact your Weatherford representative for assistance in planning your cementation program. Weatherford will ensure that the products and the installation pattern will meet your operating requirements. This investment will pay dividends over the life of the well.

Case I: Over stop collars

Case III: Between couplings and stop collars

CASE I For optimal centering, centralizers are installed over stop collars. Installation on racks eliminates lost time. This pattern is not recommended in close tolerance conditions. CASE II For optimum centering in close-tolerance pattern, centralizers are positioned between stop-collars. STA0 or STA1 bows are recommended. This pattern can be installed on racks. Close tolerance welded centralizers, with integral stop collars, are available alternatives. CASE III In this alternate close-tolerance pattern, centralizers are installed between a stop collar and the casing coupling. This pattern allows limited centralizer travel and uses only one stop collar per centralizer. Installation should not be performed on racks. CASE IV Installation of centralizers over casing coupling reduces annular flow area, concentrates lateral loads at the coupling, and requires extra rig time. Weatherford does not recommend this pattern for close-tolerance conditions where STA0 bows would be used.

Case IV: Over couplings

Case II: Between stop collars

Weatherford, Hydro-Bonder, LoDRAG & LoTROQ CentrPro, Tandem Rise Turbolizer, DOM, and Wildcat are registered Trademarks of Weatherford International, Inc.

515 Post Oak Blvd., Suite 600, Houston, Texas 77027-9496 Phone: 713-693-4000 Fax: 713-621-0994 www.weatherford.com

19

Weatherford products and services are subject to Weatherford’s standard terms and conditions. For more information concerning the full line of Weatherford products and services, please contact your authorizes Weatherford representative. Unless noted otherwise, trademarks and service marks noted herein are the property of Weatherford.

© 2001, Weatherford. All rights reserved.

Brochure # 71.01

Stage Cementing Section 4

Printed: 6/9/2006

EDC, Tomball, TX

Stage Cementing O

General discussion ³ General rationale for stage cementing ³ Definition of stage cementing ³ 2-stage versus 3-stage

O O O O

Illustration of 2-stage cement job Reasons for stage cementing Casing job types and Slurries Stage Tools Slide 2

EDC, Tomball, TX

1

Two Stage Cementing

2nd STAGE

1st STAGE Slide 3

EDC, Tomball, TX

Reasons To Perform a Stage Cementing Job O

Hydraulics ³ Avoid fracturing formation with full column of cement ³ Prevent casing collapse with full column of cement ³ Permit circulating cement above lost circulation zones

O

Economics ³ Cover selective formations without a full column of cement

O

Other ³ Allow different slurry designs for major temperature differences

Slide 4

EDC, Tomball, TX

2

Which Casing Jobs Would Qualify? O

Surface casing ³ Generally deep: 3,000’+ (1,000 m), and large casing: 16"+ (406.4 mm)

O

Intermediate casing ³ Generally deep: 8,000’+ (2,400 m), and large casing: 9-5/8”+ (244.5 mm)

O

Production casing ³ Generally deep: 10,000’+ (3,000 m)

O

Deviated wells ³ Over 30° use hydraulically operated collar Slide 5

EDC, Tomball, TX

Stage Cementing Slurries O

Commonly extended lead cements and tail-in with high strength slurries ³ Varies as conditions dictate.

O

Sometimes Lost Circulation Material (LCM) is used for the top stage. ³ If so, the ID of the ports on the stage collar must be a minimum of 2-1/2 times the diameter of the largest LCM particles, to prevent clogging of the ports.

Slide 6

EDC, Tomball, TX

3

Stage Collar

CLOSING SLEEVE PORT O-RING OPENING SLEEVE BRASS SHEAR BALL

Slide 7

EDC, Tomball, TX

Mechanical Stage Collar

Slide 8

EDC, Tomball, TX

4

Plug Sets for Davis Lynch Stage Collar CLOSING PLUG (RUN BEHIND SECOND STAGE CEMENT)

FREE-FALL OPENING DEVICE COMMONLY CALLED A "BOMB" - - ALSO CAN BE CONSIDERED A PLUG (Alternative “Pump-down” Opening Plug many be used)

FIRST STAGE SEALING PLUG (RUN BEHIND FIRST STAGE CEMENT, PASSING THROUGH THE STAGE COLLAR) Slide 9

EDC, Tomball, TX

Hydraulic Stage Collar

Slide 10

EDC, Tomball, TX

5

Stage Cementing Job Procedures (Mechanical Stage Collar) O

Check stage collar and all plugs prior to installing collar -- make sure all sizes are correct and matched to each other.

Slide 11

EDC, Tomball, TX

Stage Cementing Job Procedures (cont.) O

Stage collar made up in casing string to end up at proper depth as in job design. ³ Use thread-locking compound ³ Put tongs on pipe, above, and casing collar, below the stage tool. ³ No power or rig tongs on stage tool! ³ Do not weld on stage tool!

O

Bottom (first) stage bottom plug may be run, but usually is not run. Slide 12

EDC, Tomball, TX

6


O

Bottom stage spacer, then first stage cement is mixed. First stage sealing plug is dropped and pumped down behind first stage cement. ³ It passes through stage collar without incident. ³ It is best to slow rate and see/record this on pressure chart if possible. ³ Bumps on float collar, to end first stage

Slide 13

EDC, Tomball, TX


Immediately after the first stage sealing plug is bumped, the free-fall opening device should be dropped. ³ It is important that this be done immediately. ³ Fall rate ROT (Rule of Thumb) = 200 ft/minute (60 m/min). Ë Will take longer in viscous, heavy mud. Ë Will take less time in less dense fluid.

O

Pressure up to design pressure to open stage collar Slide 14

EDC, Tomball, TX

7


O

O

Immediately upon collar opening start circulating mud, to circulate out any cement which may be around or above the stage collar. Circulate mud while waiting to mix cement for top (second) stage. Mix and pump second stage spacer and cement.

Slide 15

EDC, Tomball, TX


O

Drop closing plug to pump down behind cement. Pressure up on closing plug to design pressure to close stage collar.

For more on stage cementing equipment, the DAVIS LYNCH catalog is included in this section of your workbook. Slide 16

EDC, Tomball, TX

8

COVER TOC ZOOM IN ZOOM OUT NEXT PREVIOUS CONTACT US PRINT

EQUIPMENT CATALOG NO. 20

Davis-Lynch, Inc. Equipment Catalog No. 20 For direct access to any of the pages below, click on the title Table of Contents (Page numbers indicated refer to actual catalog pages, not pages of CD presentation.) New from Davis Type 512-CAF Convertible Down/Up-Jet Auto-Fill Float Shoe . . . . . . . . . . . . . . . . . . . .


Davis Manual-Fill Float Shoes Float Shoe Type 500-PVTS . . . . . . . . . . . . . . . . . . Down-Jet Float Shoe Type 501-PVTS . . . . . . . . . . Double-Valve Down-Jet Float Shoe Type 501 DV-PVTS . . . . . . . . . . . . . . . . . . . . . . Guide Shoes Types 600 and 601 . . . . . . . . . . . . . Down-Jet Set Shoe with Lug Nose Type “S” . . . . . . . . . . . . . . . . . Ribbed Down-Jet Float Shoe . . . . . . . . . . . . . . . . Needle Nose Float Shoe . . . . . . . . . . . . . . . . . . . Mule Shoe Type 610 . . . . . . . . . . . . . . . . . . . . . . Texas Pattern Casing Shoes Types 800 and 800ST . . . . . . . . . . . . . . . . . . . . Davis Manual-Fill Float Collars Float Collar Type 700-PVTS . . . . . . . . . . . . . . . . . Lock-Down Anti-Rotation Plug System Type LAP Lock-Down Anti-Rotation Plug System Type LAP/N Combination Brush/Plug . . . . . . . . . . . . . . . . . . . Davis Self-Filling Float Shoes and Float Collars Pump Convert PVTS Automatic Fill-Up Shoes and Collars . . . . . . . . . . . . . . . . . . . . . . Drop Ball Convert Automatic Fill-Up Shoes and Collars . . . . . . . . . . . . . . . . . Drop Ball Convert Differential Fill-Up Shoes and Collars . . . . . . . . . . . . . . . . . Standard Stock Float Equipment Data . . . . . . . .

1 2-3 2-3 2-3 2-3 2-3 2-3 2-3 3 3 4 4 5 5

5 6 6 7

Davis Insert Float Valves Insert Float Valve Type 900 F . . . . . . . . . . . . . . . . Insert Float Fill-Up Valve Type 904 F . . . . . . . . . .

7 7

Davis Thread Compounds Thread Locking Compound . . . . . . . . . . . . . . . . . Thread Sealing and Lubricating Compounds . . . Non-Metallic Thread Compound . . . . . . . . . . . . . Super-Seal Thread Compound . . . . . . . . . . . . . .

7 7 7 7

Davis Inner-String Cementing Equipment Tag-In Equipment . . . . . . . . . . . . . . . . . . . . . . . . Pack-Off Head Assemblies . . . . . . . . . . . . . . . . . . Inner-String Adapters . . . . . . . . . . . . . . . . . . . . . Latch-Down Wiper Plug . . . . . . . . . . . . . . . . . . .

8-9 8-9 9 9

Screw-In Equipment . . . . . . . . . . . . . . . . . . . . . . Latch-In Equipment . . . . . . . . . . . . . . . . . . . . . . . Special Inner-String Cementing Equipment . . . .

10-11 10-11 11

Davis Extended Reach Equipment Flotation Collar . . . . . . . . . . . . . . . . . . . . . . . . . .

12-13

Davis Cementing Enhancement Devices Non-Welded Centralizer . . . . . . . . . . . . . . . . . . . Close-Tolerance Bow Spring Centralizer . . . . . . . Non-Welded Semi-Rigid Centralizer . . . . . . . . . . “NW” Type Centralizer Dimension and Performance Data . . . . . . . . . . . . . . . . . . . . . . Non-Welded Turbolizer . . . . . . . . . . . . . . . . . . . . Cement Basket . . . . . . . . . . . . . . . . . . . . . . . . . . “SR” Type Semi-Rigid Centralizer Dimension and Performance Data . . . . . . . . . . . . . . . . . . Non-Welded Rigid Centralizer . . . . . . . . . . . . . . Stop Collars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Spherical Stand-Off Device . . . . . . . . . . . . . . . . . “R” Type Rigid Centralizer Dimension Data . . . . Solid Body Flow Diverter . . . . . . . . . . . . . . . . . . . Centralizer Application Analysis . . . . . . . . . . . . .

14 14 14-15 14 15 15 15 16 16 16 16 17 17

Davis Stage Cementing Collars and Equipment Type 778 MC Mechanical Stage Cementing Collar . . . . . . . . . . . . . . . . . Type 777 HY Hydraulic-Opening Stage Cementing Collar . . . . . . . . . . . . . . . . . Plug Systems for Two- and Three-Stage Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . Specification Tables for Type 778 MC and Type 777 HY . . . . . . . . . . . . Packer Stage Cementing Collar Type 778-100 . . . . . . . . . . . . . . . . . . . . . . . . . .

23-25

Davis Inflatable Packers Inflatagrip Longseal Packers . . . . . . . . . . . . . . . . Packers with Continuous Reinforcing . . . . . . . . . Inflatagrip® Feature . . . . . . . . . . . . . . . . . . . . . . Integral Casing Packer . . . . . . . . . . . . . . . . . . . . . Packer Selection Data . . . . . . . . . . . . . . . . . . . . .

26 27 27 28 28

Fill and Circulate Tool . . . . . . . . . . . . . . . . . . . . .

29

Visit our website at www.davis-lynch.com

18 19 20-21 22

NEW from Davis Davis Type 512-CAF Convertible Down/Up-Jet AutoFill Float Shoe*


Consistent with the Davis tradition of offering new technology to meet operators’ requirements, we have recently introduced this shoe to the industry. The unique Type 512-CAF shoe offers several design features/ benefits to assist the operator in meeting objectives to successfully run casing to bottom, and carry out cementing operations. The field applications for this shoe range from close tolerance liners to full casing strings run to surface, or landed in a sub-sea wellhead. The list of features/benefits that this shoe provides for operators includes: • The ability for casing/liner to self-fill as it is being run into the hole. This

Fig. 1 Casing self-filling as it is run in the hole

self-filling action can significantly reduce surge pressures on the formation, and also reduce running time for casing/liner. The result of this can be substantial savings in rig time, and a reduction in the amount of drilling fluid lost during the casing/liner run. The Type 512-CAF shoe is available with several options for flow through area for the self-filling feature. (See Fig. 1). • The ability to circulate through down jets/center of shoe while running in the hole. This provides a means of washing casing/liner to seat if required. (See Fig. 2). • Once converted, the ability for cement to be pumped through upjets for optimum cement placement. (See Fig. 3). • Double valve assembly in shoe allowing for redundancy to prevent cement u-tube after completion of cementing operations. • Ball seat for conversion of shoe can serve a multi-purpose function. Conversion pressure can be adjusted to allow for setting hydraulic type liner hangers, prior to converting shoe at higher-pressure value. This allows for single ball to be utilized

Fig. 2 Circulating through down-jets/ center of shoe

1

rather than multiple balls as in previous systems. • Single ball conversion on liner applications also allows for greater flow through area for self-filling of casing/liner. This allows for maximum surge reduction, and minimizes potential of self-filling feature being compromised by solids encountered in the well bore. • Large flow through area for self-filling action makes the Type 512-CAF shoe optimum for close tolerance applications with casings being landed at the sub-sea wellhead, in deep water drilling environments. • Shoe has been drilled out with PDC bits successfully on several applications. • Components of Type 512-CAF shoe can also be installed into a collar if desired, and run together with a guide shoe. The Type 512-CAF shoe has been successfully used on numerous wells to date. Available in a full range of casing sizes, contact your Davis representative for full information. *Patent Pending

Fig. 3 Shoe converted, valves actuated. Cementing through up-jets.


Type 600

Type 500-PVTS

Type 501 DV-PVTS

Type 501-PVTS

Needle Nose Float Shoe

Type “S” Set Shoe Ribbed Down-Jet Float Shoe

2

Davis Manual-Fill Float Shoes


Davis manual-fill float shoes and float collars are simple in design and operation. They have been engineered and manufactured to withstand the high temperatures encountered and the high pressures created by differences in fluid columns when floating, landing, and cementing strings of casing. Davis’ standard design manual-fill float shoes and float collars are manufactured with the Davis PVTS valve. This valve is a spring-actuated, plunger-type, one-way check valve. It is designed to withstand high temperatures and large volumes of fluids pumped at high flow rates. It also provides an effective seal under both high- and low-pressure conditions when casing is run and cemented in either the vertical or horizontal position. The valve housing and closure element are made with a phenolic material. High strength concrete is the compound that molds the valve in the machined housing to form a strong singular unit. Despite the high compressive strength of the concrete, and the shear strength of the valve, Davis float shoes and collars are easily drilled with conventional or PDC bits. Because of its proven performance qualities, the PVTS valve is used in all manual-fill Davis float equipment including double-valve shoes and collars, and all inner-string cementing equipment including the tag-in, screw-in, and latch-in designs. Since Davis float shoes and float collars are usually manufactured from steel that has a greater wall thickness than the pipe body of the casing string they are run in, they normally have burst and collapse resistance greater than the casing string. Float Shoe Type 500-PVTS This shoe features a strong, rounded concrete nose that aids in guiding the casing string to bottom and incorporates the PVTS back-pressure valve assembly. These features make this Davis shoe highly preferred for conventional cementing jobs. Down-Jet Float Shoe Type 501-PVTS Along with all the features incorporated into the Type 500-PVTS float shoe, the popular Type 501-PVTS model features properly drilled and angled down-jet ports. The even distribution of fluid through these raised ports delivers to the user several advantages, including the added

assurance that circulation can be established when casing becomes plugged during running or is landed on bottom. The angle of the ports assists if casing has to be washed to bottom, and the spacing of the ports assists in breaking up or preventing cement channeling. Double-Valve Down-Jet Float Shoe Type 501 DV-PVTS For additional protection, choose this shoe which combines the maximum security of a unitized double check valve along with all the benefits inherent in the Type 501-PVTS. Guide Shoes Types 600 and 601 The rounded design of the concrete noses of these Davis shoes assists in guiding the casing string into the hole and safely to the bottom. Both have flat-finished concrete tops to provide strong surfaces for landing cement plugs. The Type 600 (shown) has a single fluid outlet through the nose while the Type 601 (not shown) has down-jets which deliver the efficient washing action, cement slurry distribution and other benefits of the Type 501-PVTS. Down-Jet Set Shoe with Lug Nose Type “S” This Davis shoe comes with a special drillable lug nose for use when casing is run as a liner, lowered on drill pipe and set on bottom. When bottom is contacted, the nose piece will prevent the casing from rotating when the drill pipe is released from the liner. This lug nose design can also be incorporated into self-filling shoes. Ribbed Down-Jet Float Shoe The externally raised ribs of this shoe aid in centering the casing at

bottom and promote more even distribution of cement to reduce the risk of channeling. Ribbed float collars are also available. Needle Nose Float Shoe Field-proved for over 20 years, the Davis Needle Nose Float Shoe has provided operators with an aid to run casing in adverse conditions. With its tapered aluminum nose, it has been extremely effective for running casing through tight spots, different geometric sections in the wellbore, and previous casing strings that have been damaged. It incorporates down-jet ports that create turbulent flow at the shoe for washing, conditioning, or cementing. The Needle Nose Shoe can be equipped with the Davis Type PVTS valve, which has been proven to meet or exceed API RP 10 F category III C., or with a self-filling type valve. Mule Shoe Type 610 The Davis Mule Shoe is used when the running of casing is hindered by hole conditions. When the shoe encounters a ledge in the wellbore, for example, it is rotated so that the fluid under pump pressure washes the ledge off. The shoe can also be used to facilitate getting over or by obstacles in the hole. Texas Pattern Casing Shoes Types 800 and 800ST These types of casing shoes are popular for use in reinforcing the end of the casing on shallow strings. They help the casing to run past bridges, and they provide maximum circulation through the casing. They are available with smooth-surface or sawtooth bottoms.

Casing Shoe Type 800 Mule Shoe Type 610

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Casing Shoe Type 800 ST

Davis Manual-Fill Float Collars


Float Collar Type 700-PVTS (Fig. 1, below) This Davis collar comes equipped with a flat concrete surface and load distributor plate for landing and sealing cement plugs. It normally is offered with pin and box thread connections, but it is also available with double-box connections. Both of these designs embody the positiveseal, PDC drillable Davis PVTS springoperated plunger-type valve molded in place with high strength concrete. When a back-pressure valve is not desired or required in a float collar, Davis has available the Type 701 Baffle Collar (not shown). This collar allows fluid flow in either direction and provides a strong concrete surface to land and seal cement plugs. It is often run in tandem with the Davis Type 501 DV-PVTS double-valve, down-jet float shoe. Lock-Down Anti-Rotation Plug System Type LAP (Surface launch and sub sea launch)* Available for both surface launch and sub sea launch applications, Davis offers the Type LAP plug system. The Type LAP system incorporates our first generation of mechanism to prevent plug rotation while drilling out. This system is still used on some surface launch applications

involving specialty float equipment (such as auto-fill types), and is available through a joint venture with BJ Services Co. for sub sea applications. BJ Services Co. has incorporated the Davis Type LAP mechanism into their respective sub sea launch plugs, so the BJ plugs can be run with Davis Type LAP float col- Lock-Down/Anti-Rotation Top and Bottom Cementing Plugs lars (Fig. 2, below), and provide an effective means to prevent prevents plugs from becoming disenrotation while drilling out. gaged by pressure acting on the The system features a float collar plugs from below, or being mechanithat incorporates a threaded type cally disengaged during the drill-out receiver to receive a collet type insert. process. A significant improvement A bottom plug with collet insert on over other designs that only mesh bottom, and threaded type receiver against rotation, this lock-down feaon top of plug. The top plug features ture is unique to Davis. a collet type insert on the bottom • Five-wiper premium quality plugs end. The collet feature allows for the provide for most efficient casing wipbottom plug to latch into the float ing. collar, as well as for the top plug to • Type LAP collars and plugs are field latch-in to the bottom plug. Once proven for easy drill out with PDC latched in, right hand rotation during bits. drill out tightens up the engagement • System allows for use of multiple of the plugs and collar, with the bottom plugs or no bottom plugs if threaded profiles on the collet and desired. receiver. Some notable features/bene• Davis float shoes are also available fits are: with the Type LAP insert upon • Once engaged the latch-in design request. *US Patent No. 5,234,052

Fig. 1 Type 700-PVTS

Fig. 2 Type 700 LAP Float Collar with Lock-Down/Anti Rotation Receiver

*US Patent No. 5,842,517

4

Fig. 3 Type 700 LAP/N Float Collar with Lock-Down/Anti Rotation Receiver


Lock-Down Anti-Rotation Plug System Type LAP/N (Surface launch)* Available for surface launch applications, Davis offers the Type LAP/N plug system. This system incorporates our latest generation of mechanism to prevent plug rotation while drilling out. The system features a float collar (Fig. 3, opposite page) with a heavy duty “tooth like” insert incorporated, a bottom cementing plug with heavy duty inserts incorporated on top and bottom, as well as a top plug with a heavy duty insert incorporated on bottom. The unique angled tooth design of the system allows for easy engagement between plug and collar, as well as between plugs. Notable features/benefits are: • Once engaged the angled tooth

design prevents plugs from becoming disengaged by pressure acting on the plugs from below, or being disengaged during the drillout process. A significant improvement over other designs that only mesh against rotation, this lock-down feature is unique to Davis. • Five-wiper premium Lock-Down/Anti-Rotation Plugs Type LAP/N (Surface Launch) quality plugs provide for most efficient casing wiping. • Type LAP/N collars and plugs are field proven for easy drill out with PDC bits. • Davis float shoes are also available • System allows for use of multiple with the Type LAP/N insert upon bottom plugs or no bottom plugs if request. desired.

Davis Combination Brush/Plug**

Davis Self-Filling Float Shoes and Float Collars

An alternative to more typical well bore clean-outs, the Davis Combination Brush/Plug can save operators time and associated costs, by eliminating the requirement to run a work string/casing scraper on some applications. Available for several sizes of production casings, contact your Davis representative for more information.

* US Patent 5,842,517 ** Patent Pending

Davis offers three types of self-filling equipment: the pump converted, PVTS valve equipped automatic-fill, the drop ball converted automatic-fill, and the drop ball converted differential-fill. All three types are simple in design to give top-quality performance. Pump Convert PVTS Automatic Fill-Up Shoes and Collars The Davis Type 505 AD-PVTS automatic fill-up shoe and the Davis Type 705 A-PVTS automatic fill-up collar utilize the proven Davis PVTS valve in self-filling equipment. The shoe and collar offer a fixed radial area that allows fluid to enter the casing and seek its own height. This action lowers surge pressures on formations to a minimum, reduces casing running time and, the chances of it sticking are lessened. Casing can be circulated at any time, with low rates, without converting the valve from the fill-up to the back-pressure mode. Conversion from the fill-up to the back-pressure mode can be accomplished at any time while casing is being run by introducing a pre-determined flow rate to the equipment. Furthermore, if at casing running time it is determined that self-filling equipment is not desirable, the valve can be converted by manually forcing the plunger to its fully open position and removing the three retaining balls. Doing this requires filling the casing from the top as it is run. Once conversion is carried out, all

5

the benefits of the proven Davis PVTS valve are realized, including PDC bit drillability and high pressure and temperature ratings.

Running In Type 705 A-PVTS

Valve Actuated Type 505 AD-PVTS

Davis Self-Filling Float Shoes and Float Collars–cont.


Drop Ball Convert Automatic Fill-Up Shoes and Collars The Davis Type 505 AF automatic fill-up shoe and the Davis Type 705 AF automatic fill-up collar allow maximum filling of the casing while it is being run in the hole, with the fluid entering the casing free to seek its own level. The filling action reduces casing running time and lowers surge pressures on formations to a minimum. Provided the conversion ball has not been dropped, casing can be circulated at any time without affecting the fill-up operation. Drop Ball Convert Differential Fill-Up Shoes and Collars The Davis Type 506 differential fillup shoe and the Davis Type 706 differential fill-up collar allow optimum, metered filling of the casing, while it is being run in the hole. This filling action reduces casing running time, lowers surge pressures on formations, and minimizes the possibility of sticking. Providing the conversion ball has not been dropped, casing can be circulated at any time without affecting the fill-up operation.

Valve Actuated Type 505 AF Running In Type 705 AF

Both the differential and the automatic fill-up equipment can be converted from the fill-up to the backpressure mode at anytime during the casing run by dropping the weighted ball furnished with each piece. After allowing sufficient time for the ball to reach the equipment, conversion can be achieved by applying approximately 500 psi of pump pressure. If both a shoe and collar are present in the casing string, the same ball will convert both pieces in two “like-butseparate” actions.

Running In Type 706

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Valve Actuated Type 506

Data for Davis Standard Stock Float Equipment manufactured from K-55 grade material and threaded with API Round-8 or Buttress Connections


Nominal Casing Size (Inches)

Weight Range (Lbs/Ft)

O.D. (Inches)

I.D. (Inches)

Burst (PSI)

Collapse (PSI)

4-1/2

9.5–13.5

5.000

4.031

9,300

9,600

5

11.5–21.0

5.563

4.439

9,720

9,950

5-1/2

14.0–23.0

6.050

4.950

8,750

9,050

7

23.0–38.0

7.656

6.276

8,650

9,000

7-5/8

20.0–39.0

8.500

6.969

8,650

9,000

8-5/8

24.0–44.0

9.625

8.017

8,000

8,400

9-5/8

32.3–53.5

10.625

8.921

7,700

8,100

10-3/4

32.7–55.5

11.750

10.050

6,950

7,350

11-3/4

38.0–65.0

12.750

11.000

6,600

7,000

13-3/8

48.0–72.0

14.375

12.615

5,850

5,850

16

65.0–109.0

17.000

15.250

4,950

4,250

18–5/8

87.5–117.5

20.000

17.755

5,400

5,050

20

94.0–133.0

21.000

19.125

4,250

3,150

Standard stock Davis Float Equipment meets or exceeds the burst and collapse ratings of N-80 Grade Casing for most weights within the range shown for each size. NOTE: All burst and collapse pressure ratings are calculated in accordance with API Bulletin 5C3, Sixth Edition, October 1, 1994.

Davis Insert Float Valves Insert Float Valve Type 900 F The Davis Insert Float Valve Type 900 F is available for use in wells of moderate depth using API 8 round short thread or buttress casing. Davis Insert Fill-Up Valve Type 904 F Like the Type 900 F, the Davis Insert Fill-Up Valve Type 904 F is available for use in moderate depth wells, using API 8 round short-thread or buttress casing. This valve allows continuous fill of the casing as it is run into the hole. A drop-ball converts the 904 F into a conventional back-pressure valve.

Insert Float Valve Type 900 F

Insert Float Fill-Up Valve Type 904 F

Davis Thread Compounds Davis-Lock Thread Locking Compound The Davis-Lock thread locking compound is a strong epoxy-based compound for use on all threaded connections to prevent back-off and loosening of joints. The one-pound kit contains the base, catalyst and applicator. Davis API Modified Thread Compound This Davis thread compound conforms to the specifications of API Bulletin 5A2. It is recommended for use on casing, tubing, and in line pipe. Davis Non-Metallic Thread Compound This Davis thread compound has been formulated as an environmentally safe replacement for API modified thread compound that will meet

or exceed the listed performance objectives in API Bulletin 5A2. Davis Super-Seal Thread Compound Davis developed the Super-Seal thread compound to provide longlasting, high pressure sealing on all API threaded joints, especially tubing

7

and casing. The compound contains molydisulfide and TFE resin for a high-pressure seal. Joints coated with Davis Super-Seal hold better and make up easier with less torque and still break clean without damage.

Stop Collar

Drill Pipe Centralizer


Casing

Pack-Off Head Assembly

Tag-In Adapter Type B-122C

Type 501 DVT-PVTS

Tag-In Float Collar Type 700 T-PVTS

Down-Jet Float Shoe Type 501-PVTS

Drill Pipe Bowl and Slips

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Davis Inner-String Cementing Equipment


Excellent cement jobs at reduced costs have boosted inner-string cementing equipment to the forefront of operator popularity. Davis was among the first to offer the inner-string systems, and continues today to have the most complete line of systems available in the industry. Davis equipment is designed with a taper in the top of the concrete to guide the adapter on the bottom of the inner-string into the receiver incorporated in the float shoe or collar. All three styles of adapter-toreceiver adjoinments engage dualseal mechanisms to prevent fluid leakage. The primary seal consists of elastomer seals compressed in a smooth bore. The 45° bearing face effected when the adapter and receiver adjoin creates the secondary seal. Davis offers three proven systems for inner-string cementing: the Tag-In system, the Screw-In system, and the Latch-In system. The equipment used in these systems can be manufactured in virtually any size and thread, and as single or double-valve float shoes (with or without ports), float collars, and baffle collars. An option available when ordering Davis inner-string equipment is a latch-down wiper plug. This plug follows the cement and wipes the drill pipe. Once properly latched down, the plug and latch mechanism act to check back pressure, giving additional assurance that cement will be retained in the desired position and the inner-string (drill pipe) can be immediately pulled out of the hole. Davis is the only company that stocks in local inventories all the accessory items required to perform inner-string cement jobs in a timely and efficient manner. These items include a set of drill pipe bowl and slips, a false rotary plate, and a centralizer to center the drill pipe inside the casing. Davis Tag-In Equipment Tag-In float equipment incorporates a receiver built into the float equipment (shoe or collar) that receives an adapter made up to the bottom of the inner string (usually drill pipe). The tapered concrete finish around the receiver guides the adapter into it. The Type B-122-C TagIn Adapter is engaged to the receiver by straight-in movement, No rotation is required. Once engaged, a primary

and secondary seal are effected. Disengagement of the seal is achieved by picking the adapter up and out of the receiver. Once again, no rotation is required. A popular choice of equipment for inner-string cementing larger diameter casings, from both onshore and offshore rigs, is the Davis Type 501PVTS Float Shoe and the Type 700 TPVTS Tag-In Float Collar. This equipment provides all the benefits that come with inner-string cementing through a float collar, including the option to run one or more shoe joints and the option to displace cement below the float collar without creating a “wet shoe.” For those preferring to inner-string cement through a shoe, Davis offers

the Type 501 DVT-PVTS Double-Valve, Down-Jet, Tag-In Float Shoe. This float shoe incorporates all the features and benefits built into the 501PVTS Float Shoe and the Type 700 T Tag-In Float Collar. Pack-Off Head Assemblies Davis also has available the largest and most complete inventory of casing to drill pipe pack-off heads in the industry, if well hydraulics dictate the use of one when inner-string cementing. These heads are designed to seal the drill pipe/casing annulus and allow pressure to be applied to it. This pressure serves to offset pump pressure that creates collapse loading whenever inner-string cementing operations are conducted.

The Three Adapters of the Davis Inner-String Systems

Davis Latch-Down Wiper Plug This plug is optional with Davis Tag-in and Screw-in systems whether cementing through a shoe or collar. It is available for all drill pipe sizes and can be manufactured from non-metallic components if drilling out with a PDC bit is intended.

9

Drill Pipe

Davis Conductor Casing Hanger Port Davis Drive Pipe Landing Ring


Drive Pipe

Conductor Casing

Type 501 DVS-PVTS

Screw-In Adapter

Type 700 S-PVTS Screw-In Assembly Type 501 DVSLP-PVTS Double Valve, Down-Jet, Screw-In Float Shoe w/Latch-Down Plug

Type 700 L-PVTS

Type 501 DVSLP-PVTS Screw-In Shoe with Hanger Assembly

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Davis Screw-In Equipment Screw-In float equipment allows the adjoining of the inner-string to the casing at the float equipment. This adjoinment supports the load of the casing, allowing it to be lowered to bottom and inner-string cemented while being reciprocated. The equipment incorporates a strong receiver built into the float equipment (shoe or collar) that is capable of handling loads up to 300,000 pounds. Adjoinment between the Type B-120-B Adapter and the receiver is accomplished by applying left-hand rotation to the inner-string. No torque is required. Once the receiver and adapter are engaged, primary and secondary seals are effected between the two. Disengagement is attained by applying right-hand rotation to the inner-string while gradually picking it up. Davis Screw-In equipment has created a whole new realm of economical uses with regard to its multiple applications. Among them: 1. Offshore, running and landing of the conductor casing string at either the mudline or the production deck. The string can be landed in tension by utilizing a Davis Drive Pipe Landing Ring and Davis Conductor Casing Hanger. (See graphic opposite page). This allows the operator to effectively seal off the conductor/ drive pipe annulus. A second option is to allow the casing string to be landed on bottom or free standing in compression. Either application can save the operator rig time and related costs by eliminating the need for nippling-up well control equipment on the conductor casing string. When conductor casing is suspended on a landing ring, at either the mudline or the production deck, the tapered top of the Davis casing hanger serves as an aid in protecting and guiding the bits to be used for the next hole section into the top of the liner. In addition to this, Davis can customize the top of the casing hanger to receive most brands of conventional mudline suspension or wellhead housing equipment. When conductor casing is set on bottom in compression, Davis offers the Type B-125 bit guide (see photo) that screws into the top of the liner. In addition, Davis manufactures a fluted casing hanger that is designed to land on this bit guide and suspend surface casing. Most brands of conventional, modular mudline suspen-

sion equipment can then be placed in the surface casing string for the purpose of landing and suspending ensuing casing strings. 2. Reciprocating full strings of casing while inner-string cementing. This application has proven extremely effective on geothermal wells where the absence of cement voids in the annulus is exceptionally critical if eventual casing collapse is to be avoided. 3. Setting a large-diameter liner to eliminate the cost of an expensive, conventional liner hanger, and realizing all the benefits inherent in innerstring cementing.

Type B-125 Bit Guide

As with all Davis inner-string equipment, the Screw-In style is available in several models including the Type 700 S-PVTS for those who prefer cementing through a float collar, and the Type 501 DVS-PVTS for those who prefer cementing through a float shoe. Davis Latch-In Equipment Davis also offers Latch-In equipment for inner-string cementing. It acts similar to Tag-In equipment with the additional feature of positively locking the adapter into the receiver. The Type B-113 Adapter is engaged to the receiver by straight-in movement. No rotation is required. Disengagement is accomplished by rotating the drill pipe one turn to the right and picking up on it. This action “un-jays” the collet that locks the adapter in place and allows it to compress and release from the receiver. The adapter can also be released without damaging it by pulling approximately 40,000 pounds over the inner-string weight. This action

11

results in a safety sleeve being sheared out of the receiver. This backup release feature should only be used if necessary. Davis Latch-In equipment can be used when cementing from floating drilling vessels. It can also be used if unusually high pump rates are anticipated during cementing operations. The Latch-In mechanism will act to anchor the inner-string to the casing, eliminating the possibility of hydraulically pumping or “lifting” it out. The Latch-In style of inner-string equipment is available in several models including the Type 700 L-PVTS Float Collar. This model provides the operator with all the benefits that come with inner-string cementing through a float collar, including the option to choose several shoe joints and the option to overdisplace cement below the float collar without creating a “wet shoe.” Davis Special Inner-String Cement Equipment Davis has available, in either a shoe or collar, open-ended equipment that can be used to conduct inner-string cementing operations. The design of this equipment makes its use advantageous particularly when large-diameter/thin-walled casings of the type commonly run in storage wells are being cemented. The equipment incorporates two receivers, one to receive the standard Tag-In adapter and one to receive a special latchdown wiper plug that follows cement. A popular choice for this application is the Davis Type 601 TLP DownJet, Tag-In Guide Shoe with LatchDown Plug receptacle. Its open-ended feature allows casing to self-fill as it is run in the well. This eliminates the time that would normally be required to manually fill the casing. Once casing is on bottom, the inner-string is run and seal engagement occurs by use of the standard Tag-In adapter. A Davis Pack-Off Head Assembly is often rigged up at this point. At the conclusion of cement displacement, the special latch-down wiper plug is landed and locked into the shoe. Once latched, this plug provides the back-pressure check that is necessary to retain cement in the desired position.

Davis Extended Reach Equipment


Davis Flotation Collar* The patented Davis Flotation Collar (DFC) is designed for use in running casing in substantially horizontal wellbores. Incorporated into the casing string, the device serves as a temporary barrier inside the casing. In so doing, it allows the portion of the string below it to be filled with air (no fluid) and the portion above it to be filled with drilling fluid. Floating the bottom portion of the casing reduces the drag against the wellbore, while filling the upper portion with drilling fluid adds weight to the casing string to push it into the hole. This feature facilitates running casing in highly deviated wells and, in many cases, permits successful casing runs that would otherwise be extremely difficult if not impossible. Once the opening sleeve is activat-

Mud-filled casing

ed by casing pressure, allowing the drilling fluid to displace the air in the lower section of the casing string, normal cementing operations can begin immediately. Additional pressure on the bottom cementing plug releases the DFC assembly so that it can be pumped down to the float collar. The top cementing plug displaces the cement and lands and seals on the bottom cementing plug/DFC assembly. Unlike earlier devices that must be set inside the casing and then retrieved after landing the casing (requiring one round trip of the drill pipe and spacing the top of the last casing joint at the rotary table), the Davis Flotation Collar is installed in the same manner as a float collar. Applying pressure to the inside of the casing string is all that is required

Davis Flotation Collar

to release the trapped air at the bottom of the casing string. This pressure is adjustable at time of manufacture to accommodate different pressure requirements. The Davis Flotation Collar is selfcontained and requires no other running, setting or retrieving tools. The inner sleeves of the device provide a good seal for the cementing plug against the float collar, and they are easily drilled out with either PDC or conventional rock bits when drilling the float equipment.

*Davis-Lynch does not warrant that use of the Davis Flotation Collar in a Selective Flotation System is free from infringement of any patented methods. Use of the Davis Flotation Collar in such a system may, for example, require permission from Unocal under U.S. Patent 4,986,361.

Davis Special Application Float Collar

Davis Special Application Float Shoe

Davis Semi-Rigid Centralizer

Air-filled casing

Mud

Davis Flotation Equipment Package

12

Opening Sleeve

Bottom Plug Seal

Shear Balls

Plug


Circulating Ports

Bottom Sleeve

Seal

1.

Davis Flotation Collar (DFC) Bottom portion of casing is run dry (not filled with fluid), with DFC installed at desired depth. Casing above the DFC is filled with drilling fluid as casing run continues to desired depth.

2.

Davis Flotation Collar (DFC) Casing pressure is increased until the opening sleeve shifts down to permit fluid and air to swap. After a fluid stabilization period, the casing is filled with drilling fluid.

3.

Davis Flotation Collar (DFC) Bottom cementing plug is launched ahead of cement. After landing on the bottom sleeve, it pushes both DFC sleeves ahead of the cement to the float collar below.

Top Plug

Casing Bottom Plug

Casing

Bottom Plug Float Collar Float Collar

4.

Davis Flotation Collar (DFC) Bottom cementing plug and sleeves land and seal on the float collar. Bottom cementing plug ruptures, and cement is pumped through and out of the float equipment.

5.

Davis Flotation Collar (DFC) Top cementing plug is displaced and seals on bottom cementing plug/DFC assembly at the float collar.

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Davis Cementing Enhancement Devices


Davis Non-Welded Centralizer* Davis offers a full line of patented, non-weld centralizers. The centralizers feature a unique interlocking adjoinment between the end collar and bow spring, which makes for a strong singular unit. Davis Type “NW” centralizers are designed to exceed the performance requirements of API Specification 10D for both starting and restoring forces. (See data table this page) Other design features of the Type “NW” centralizer include: • Bow springs made of an alloy steel which are heat treated and tempered to a hardness to ensure proper and consistent spring characteristics. • End collar hinges that are folded to the inside. This acts to minimize the collar stretch that tends to occur when centralizers encounter

tapers common to some pipe connections. • A reinforcing rib stamped into the end collar. This acts to strengthen it and ensure maintenance of its round configuration during transport. • Several different spring bow heights that are available to accommodate most any casing-to-hole configuration. • Centralizers with built-in stop devices as well as those for unusual sizes available on request. Davis Close-Tolerance Bow Spring Centralizer In applications for running casing in close tolerances or slim holes, Davis offers a special type bow spring centralizer for these requirements. To provide optimum performance in close-tolerance holes, these centralizers feature low starting forces and high restoring forces. Centralizers consist of a solid type end collar for slipping over the pin end of casing joint. Some features/benefits include: • Designed to meet or exceed API Specification 10D for starting and restoring forces.

• Available with set screws incorporated for integral stop, or can be run between stop devices for applications when casing is to be rotated. • Typical applications include: 5-inch casing inside 6-inch hole, 7 5/8-inch casing inside 8 1/2-inch hole, and 9 5/8 inch casing inside 10 5/8-inch hole. Other sizes are available upon request. Davis Non-Welded Semi-Rigid Centralizer (SRC) This Davis product features uniquely profiled bows that simultaneously provide the operator with those features found desirable in both spring bow and rigid centralizers. The result is a centralizer that far exceeds the performance standards set forth in API Specification 10D.

Davis “NW” Type Centralizer Dimension and Performance Data Casing Size (In Inches)

Hole Size (In Inches)

Product Number

Bow O.D. (In Inches)

4-1/2 4-1/2 4-1/2 4-1/2 5 5 5 5 5-1/2 5-1/2 5-1/2 5-1/2 5-1/2 7 7 7 7-5/8 8-5/8 8-5/8 9-5/8 10-3/4 10-3/4 10-3/4 11-3/4 11-3/4 13-3/8 16 16 18-5/8 18-5/8 20 20

6 6-1/4 6-1/2 7-7/8 6-1/4 6-1/2 7-7/8 8-1/2 7-7/8 8-1/2 8-3/4 9-7/8 12-1/4 8-1/2 8-3/4 9-7/8 9-7/8 11 12-1/4 12-1/4 12-1/4 13-1/2 14-3/4 14-3/4 15-1/2 17-1/2 20 22 22 24 24 26

0450-NW2C 0450-NW2C 0450-NW3C 0450-NW4C 0500-NW1C 0500-NW2C 0500-NW4C 0500-NW4C 0550-NW3C 0550-NW4C 0550-NW4C 0550-NW5C 0550-NW6C 0700-NW2C 0700-NW3C 0700-NW4C 0758-NW3C 0858-NW3C 0858-NW5C 0958-NW8C 1034-NW2C 1034-NW4C 1034-NW5C 1134-NW4C 1134-NW5C 1338-NW5C 1600-NW5C 1600-NW6C 1858-NW5C 1858-NW6C 2000-NW5C 2000-NW6C

7-1/8 7-1/8 7-5/8 9-1/8 7-1/8 7-5/8 8-1/8 9-5/8 8-5/8 10-1/8 10-1/8 11-1/8 13-5/8 9-5/8 10-1/8 11-5/8 10-3/4 11-3/4 14-1/4 14-3/4 13-3/8 15-3/8 16-3/8 16-3/8 17-3/8 19 21-5/8 24-1/8 23-1/4 26-3/4 25-5/8 28-1/8

*U.S. Patent No. 4,909,322

14

Starting Force (In Lbs) API Davis 464 464 464 464 520 520 520 520 620 620 620 620 620 1040 1040 1040 1056 1440 1440 1600 2040 2040 2040 2160 2160 2400 2600 2600 3500 3500 3760 3760

361 251 355 264 175 273 190 360 240 520 227 280 240 720 795 720 550 400 1120 1389 511 645 660 624 940 830 844 1161 2010 740 1360 1220

Restoring Force (In Lbs) API Davis 464 464 464 464 520 520 520 520 620 620 620 620 620 1040 1040 1040 1056 1440 1440 1600 1020 1020 1020 1080 1080 1220 1300 1300 1750 1750 1880 1880

3000+ 1140 2070 1040 650 3000+ 1020 1650 650 1210 1310 1180 680 3000+ 3000+ 1910 1467 1470 1850 2175 2185 1385 1290 1411 1530 2330 1570 2530 3000+ 1850 1930 2200


As with the standard Davis NonWelded Centralizer, the bows of the SRC are manufactured from alloy steel which is heat treated and tempered. During assembly they are adjoined to the end collars by the Davis patented interlocking method. The design of the SRC’s bows produces centralizers that have starting forces far below API maximums along with very low drag forces. The spring characteristic of the bows allows the SRC to compress in order to get through tight spots and severe doglegs that may be present downhole. While the manufacture of the bows produces characteristics normally associated with standard spring bow centralizers, the double-crested profile of the SRC bow provides restoring forces that far exceed those standards set forth in API Specification 10D and which are normally associated with rigid

centralizers. The SRC is ideally suited for running in horizontal and highly deviated wells where low running forces are a must. It can be run over casing connections or stop collars and, if requested, can be manufactured with a built-in stop device. Davis Non-Welded Turbolizer This is a centralizer with metal fins installed on the bows to help induce turbulence in the cement slurry during pumping operations. Like the spring bows, the fins are made of heat-treated alloy steel. This makes them flexible, which minimizes damage while moving downhole. The Davis Turbolizer incorporates the same non-welded end collar-tospring-bow interlocking adjoinment as the Davis centralizer. Turbolizers are available in the same sizes and bow heights as centralizers. As with the Davis centralizer, turboliz-

ers can be manufactured with a built-in stop device. These items are available on special order. Davis Cement Basket A simple, economical type of annular packoff, the Davis Cement Basket is commonly used in situations where porous or weak formations require help in supporting a cement column. It is constructed of thin steel petals arranged in an overlapping pattern and reinforced by spring steel ribs. Its design allows cement to flow in an upward direction, yet helps to prevent it from falling downward. The basket is easily installed by sliding it over the pin end of a casing joint, prior to make-up of the joint. Travel range can be limited by a stop ring or by couplings. Available in sizes 4 1/2” and larger, the Davis Cement Basket is most effective when centralized and placed into a gauged section of the hole.

Davis “SR” Type Semi-Rigid Centralizer Dimension and Performance Data Casing Size (In Inches)

Hole Size (In Inches)

Product Number

Bow O.D. (In Inches)

4-1/2 4-1/2 4-1/2 4-1/2 *5 5 5 5-1/2 5-1/2 5-1/2 5-1/2 *7 7 7 7-5/8 *8-5/8 8-5/8 9-5/8 **10-3/4 10-3/4 10-3/4 11-3/4 11-3/4 13-3/8 16 18-5/8 20 20

6 6-1/4 6-1/2 7-7/8 6-1/2 7-7/8 8-1/2 7-7/8 8-1/2 8-3/4 9-7/8 8-1/2 8-3/4 9-7/8 9-7/8 11 12-1/4 12-1/4 12-1/4 13-1/2 14-3/4 14-3/4 15-1/2 17-1/2 20 22 24 26

0450-SR1C 0450-SR2C 0450-SR3C 0450-SR7C 0500-SR1C 0500-SR6C 0500-SR8C 0550-SR4C 0550-SR6C 0550-SR7C 0550-SR9C 0700-SR1C 0700-SR2C 0700-SR6C 0758-SR4C 0858-SR5C 0858-SR8C 0958-SR5C 1034-SR1C 1034-SR5C 1034-SR9C 1134-SR6C 1134-SR8C 1338-SR9C 1600-SR9C 1858-SR7C 2000-SR9C 2000-SR10C

6.06 6.38 6.63 7.88 6.56 8.00 8.68 7.88 8.50 8.88 9.68 8.63 8.88 10.00 10.00 11.00 12.31 12.38 12.38 13.50 15.00 14.81 15.50 17.63 20.25 22.06 24.25 26.13

Starting Force (In Lbs) API Davis 464 464 464 464 520 520 520 620 620 620 620 1040 1040 1040 1056 1440 1440 1600 2040 2040 2040 2160 2160 2400 2600 3500 3760 3760

*Starting force derived from testing over stop collars. **Starting force derived from testing over stop collars, recommended running only over a stop device.

15

171 <150 <150 <150 <150 <150 <150 <150 <150 <150 <150 <150 783 <150 <150 276 <150 683 <150 <150 777 180 180 410 745 <150 605 757

Restoring Force (In Lbs) API Davis 464 464 464 464 520 520 520 620 620 620 620 1040 1040 1040 1056 1440 1440 1600 1020 1020 1020 1080 1080 1220 1300 1750 1880 1880

4000+ 4000+ 3180 3000 4000+ 3585 4000+ 1720 2910 2540 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+ 4000+


Davis Non-Welded Rigid Centralizer This Davis product features the patented adjoinment between end collar and spring bow first introduced in the Davis non-welded bow centralizer, along with all the features that operators demand in a rigid centralizer. These include the reduction in drag associated with running pipe in deviated and horizontal wells, the ability to provide optimum concentricity during casing cementing operations, and the ability to function equally well in either open or cased hole. These centralizers are offered in a wide assortment of bow sizes to accommodate most casing-to-hole configurations. Davis Stop Collars Davis offers two designs of stop collars: a friction-grip type and a setscrew type. The friction grip type is hinged and incorporates a nut/bolt assembly which, when tightened,

draws the stop collar into a friction grip around the circumference of the pipe. It is manufactured from steel that meets ASTM A 569 specifications. The set-screw type is a one-piece

Stop Collar

Davis also offers a premium one-piece stop-collar, with set screws for superior holding capability.

model that slips on the pipe and is held in place by tightening set screws against the casing. It is manufactured from steel that meets AISI M 1020 specifications. This design offers superior holding capability and is especially applicable in close tolerance situations.

Davis “R” Type Rigid Centralizer Dimension Data Casing Size (Inches) 4 1/2 4 1/2 4 1/2 4 1/2 5 5 5 5 1/2 5 1/2 5 1/2 5 1/2 7 7 7 7 5/8 8 5/8 8 5/8 9 5/8 10 3/4 10 3/4 10 3/4 11 3/4 11 3/4 13 3/8 16 16 18 5/8 18 5/8 20 20

Hole Size (Inches) 6 6 1/4 6 1/2 7 7/8 6 1/2 7 7/8 8 1/2 7 7/8 8 1/2 8 3/4 9 7/8 8 1/2 8 3/4 9 7/8 9 7/8 11 12 1/4 12 1/4 12 1/4 13 1/2 14 3/4 14 3/4 15 1/2 17 1/2 20 22 22 24 24 26

Product Number 0450-RAC 0450-RAC 0450-RBC 0450-RFC 0500-RAC 0500-REC 0500-RFC 0550-RCC 0550-REC 0550-RFC 0550-RIC 0700-RAC 0700-RBC 0700-REC 0758-RCC 0858-RCC 0858-RGC 0958-RDC 1034-RAC 1034-RDC 1034-RHC 1134-REC 1134-RGC 1338-RHC 1600-RHC 1600-RJC 1858-REC 1858-RIC 2000-RHC 2000-RJC

Bow O.D. (Inches) 5 3/4 5 3/4 6 1/8 7 5/8 6 1/4 7 3/4 8 1/8 7 5/8 8 1/4 8 5/8 9 5/8 8 1/4 8 5/8 9 3/4 9 3/4 10 3/4 12 1/8 12 1/8 12 13 1/4 14 5/8 14 1/2 15 1/4 17 1/4 19 7/8 21 7/8 21 3/8 22 3/4 23 7/8 25 7/8

16

Davis stop collars are stocked in all popular sizes ranging from 4 1/2″ to 20″ Unusual sizes are available on request. Davis Spherical Stand-Off Device* A new product that Davis is introducing is a spherical shaped standoff device. This device is designed to promote positive stand-off, and significantly reduce the drag forces that are normally associated with other positive stand-off devices. Features/benefits include: • Spherical curvature of the blades in the vertical direction significantly reduces drag, prevents the blades from having “plowing effect,” and reduces build up of cuttings around stand-off device. • Spherical curvature of the blades around the circumference prevents edge of blades from embedding into formation for applications when casing is rotated. • Blade shape and spacing of blades allows for optimum flow area around the blades of the device. • Aluminum material prevents damage to the OD of the casing or previous casing strings, and reduces friction. • Special high performance coating further prevents damage to casing strings and prevents galvanic corrosion. Coating also reduces tendency for cuttings to adhere to blades of device and reduces friction. • Designed for both common and close tolerance applications. • Utilized on applications for rota-

Spherical Stand-Off Device

tion or reciprocation. Contact your local Davis representative for more information.

rotation. • Create a spiral turbulence around the casing to promote uniform cement bonding.

*Patent pending


Davis Solid Body Flow Diverter The Davis Solid Body Flow Diverter (SBFD) provides a rigid means of holding casing off the well bore. With blades placed at an angle, it creates a swirling motion that promotes more cleansing action for mud removal, more circulating area, and sufficient contact with the bore wall to provide centralization and prevent wall sticking. SBFDs can be installed to remain stationary or move freely on the casing. Length of movement is determined by placement of stop devices or by couplings where applicable. In stationary positions, SBFDs will normally provide stand-off to allow circulation all around the casing string. When allowed to move freely, they serve as a series of bearings during reciprocation to reduce frictional drag. Available in most casing/hole size configurations, the SBFDs have been successfully used to: • Maintain centralization through positive stand-off. • Enhance the effects of mud-wash pumped ahead of cement slurries. • Aid in the removal of gelled mud from the annulus. • Reduce torque required for casing

Davis Centralizer Application Analysis Davis will, on request, run a computer-analyzed program that will recommend centralizer placement and project casing stand-off. All that is required are some simple pipe and well data, including casing size, casing weight, casing seat, hole size, mud weight and, when deviation is present, full survey data, including kickoff point, rate of build and final deviation. Since centralization is most critical through the cemented interval, anticipated top of cement is also

Solid Body Flow Diverter

17

requested. With these data, the computer can be set up to run the spacing/stand-off programs in two different modes. The first and most effective mode is “variable spacing.” In this program, the relevant well data are entered and the computer calculates the number of centralizers to run, and how to space them, in order to meet whatever percent stand-off the customer desires for cement emplacement. The second mode is “constant spacing.” Using the same data required for the variable spacing mode, this program calculates what stand-off can be expected when the customer rather than the computer dictates the number of centralizers to be run, and at what spacing they will be run.

DAVIS STAGE CEMENTING COLLARS AND EQUIPMENT For over 20 years, Davis stage cementing collars have been used by operators for their special applications. Now Davis offers three stage collar designs: a mechanically opened tool, a hydraulically opened tool, and a mechanically opened tool with a built-in inflatable packer.

Type 778 MC Mechanical Stage Cementing Collar


While now established as a fieldproven tool, this tool continues to be the subject of research and development to find new materials for faster drill-out time, greater PDC bit drillability and better metal-to-metal sealing. Features of the 778 MC Stage Cementing Collar include: • Tools can be made from material

grades up to 135,000 psi minimum yield, including material suitable for sour gas service. • All parts are custom fitted and subjected to extensive quality control standards for maximum performance downhole. • The connection that adjoins the stage collar body and the bottom sub effects a metal-to-metal seal and engages a back-up elastomer seal, the two of which are designed to provide gas-tight pressure integrity. • No welds are used on any portion of the tool. • The reduced length of the tool minimizes the effect of bending stresses. • The seals providing internal and external pressure integrity are housed in the stage collar body and remain

stationary throughout operation, minimizing chances of their being damaged. • The pressure-relief design prevents fluid trapping and compression between the opening device and the closing plug during the closing phase of the tool’s operation. • The closing sleeve is held in the closed position by an internal lock ring. • Both the opening and closing sleeves lock against rotation for easy drill-out. • A minimum amount of aluminum and rubber are the only materials encountered during drill-out. Plug sets for four different cementing applications are available (pp. 20, 21).

Closing Plug

Closing Sleeve

Opening Sleeve

Fluid Ports

Double Seals

Broken Shear Mechanism

Lock Ring

Brass Shear Mechanism Anti-Rotation Feature

Free-Fall Opening Device

Body Connection with Metal-to-Metal Seal and Elastomer Back-up

Running Position Pin and Box threads are identical to the casing threads. Stage collar integral connection is designed for gas tightness. Seals on opening sleeve provide internal and external pressure integrity across the fluid ports.

Opened Position Opening device has landed and, after pressure is applied, the lower set of shear mechanisms is broken and the sleeve shifts downward to uncover the fluid ports. Pumping operations can now be conducted through the stage collar.

18

Closed Position The closing plug has landed and, after pressure is applied, the upper set of shear mechanisms is broken and the sleeve shifts downward, shutting off the fluid ports. Double seals above and below the ports provide pressure integrity.

Type 777 HY Hydraulic-Opening Stage Cementing Collar


This stage collar features an opening sleeve with area differences on opposite ends that allows it to be manipulated hydraulically. The closing sleeve is identical to the one contained in the Davis Type 778 MC Mechanical Stage Cementing Collar. The development and introduction of this model was spurred on by the tremendous upswing in horizontal drilling activity that has occurred in recent years. The hydraulic-opening feature makes this tool’s use very practical in horizontal wells. The elimination of the need to use a mechanical opening device has several other merits. Casing runs in highly deviated wells can now be two-

stage cemented without having to use continuous displacement type plugs. In certain applications, liners run with drill pipe can be run in conjunction with one or several inflatable packers and used to isolate and selectively cement certain casing intervals. Slotted or pre-drilled liner can be run below a Davis inflatable packer/hydraulic stage collar assembly, allowing cement to be pumped above the packer and isolated from highly sensitive producing zones. Along with all the features inherent in the 778 MC Stage Cementing Collar, the Type 777 HY offers: • Effective differential area on the opening sleeve that generates a high

opening force while requiring only optimal pressure to do so. • The ability to open immediately upon the completion of first-stage cement displacement. • Opening pressure values that can be adjusted at the time of assembly to assure that all inflatable packers or other hydraulic tools present in the casing string will be triggered at the correct juncture. (See Specification Table on page 22)

Closing Plug

Closing Sleeve

Differential Opening Sleeve

Fluid Ports

Brass Shear Mechanism

Broken Shear Mechanism

Lock Ring

Shouldered Anti-Rotation Feature (Not shown)

Body Connection with Metal-to-Metal and Elastomer Back-up

Running Position Pin and Box threads are identical to the casing threads. Stage collar integral connection is designed for gas tightness. Seals on opening sleeve provide internal and external pressure integrity across the fluid ports.

Double Seals

Opened Position Pressure is applied against the landed and sealed first-stage plug, breaking the lower set of shear mechanisms to allow the sleeve to shift downward and uncover the ports. Pumping operations can now be conducted through the stage collar.

19

Closed Position The closing plug has landed and, after pressure is applied, the upper set of shear mechanisms is broken and the sleeve shifts downward, shutting off the fluid ports. Double seals above and below the ports provide pressure integrity.

DAVIS STAGE CEMENTING COLLARS AND EQUIPMENT

Stage Cementing Plug Systems


Closing Plug

Two-Stage Cementing with the Type 778 MC using a First-Stage Sealing Plug, Free-Fall Opening Device, and Closing Plug

Two-Stage Cementing with the Type 778 MC using a By-Pass Plug, Shut-Off Plug and Baffle, Free-Fall Opening Device, and Closing Plug*

1. A Davis float shoe and float collar along with the Type 778 MC Stage Collar, are installed in the casing string and the casing is run to bottom.

1. A Davis float shoe and float collar along with the Type 778 MC Stage Collar, are installed in the casing string and the casing is run to bottom. The yellow shut-off baffle is installed in the casing string at least (1) one joint above the Davis float collar. If API threads are run (8RD or Buttress) the baffle can be installed in the “J” section of a coupling. If premium threads are run, a separate baffle collar must be run.

2. Circulation is established and first-stage cement is mixed and pumped.

Closing Plug

3. The first-stage sealing plug is launched and cement is displaced. At the conclusion of displacement, the first-stage sealing plug lands and effects a seal against the Davis float collar. No baffle is required.


4. The free-fall opening device is dropped and allowed to gravitate to position. Pressure is applied to the casing and the stage collar is opened.


5. Circulation is established and second-stage cement is mixed and pumped.

3. After cement is mixed and pumped, the shut-off plug is launched and cement is displaced. At the conclusion of displacement, the shut-off plug lands and effects a seal in the shut-off baffle.

6. The closing plug is launched and cement is displaced. At the conclusion of displacement, the closing plug lands and effects a seal in the stage collar. Pressure is applied to the casing and the stage collar is closed. First Stage Sealing Plug

2. After the hole is conditioned, the by-pass plug with the yellow nose piece is launched ahead of first-stage cement. This plug will pass through the shut-off baffle and land on any Davis manual- or self-fill float collar. Once landed, approximately 50 psi will invert the wipers on the by-pass plug and allow cement to pass.

First Stage Shut-Off Plug

Shut-Off Baffle Painted Yellow

4. The opening of the stage collar and the ensuing second-stage cementing and closing of the stage collar are carried out identically to that described for two-stage cementing with first-stage sealing plug.

*NOTE: When using the Type 777 HY Hydraulic-Opening Stage Collar, the standard plug system is a first-stage shut-off baffle, a first-stage shut-off plug, a contingent opening device, and a closing plug. A first-stage latch-in plug with a special Davis float collar is available on request. Painted Yellow

By-Pass Plug

20

Three-Stage Cementing with the Type 778 MC and the Type 778 MC-3S Stage Cementing Collars

Pump Down Opening Plug

1. After first-stage cement is mixed and pumped, release the by-pass plug and begin displacing. Once the calculated volume of displacement fluid between the stage collar and the float collar has been pumped, less a pre-determined amount acting as a safety buffer, release the pump-down opening plug.

Closing Plug

2. As the pump-down opening plug approaches the stage-collar, slow the pump rate to 1–2 bbls./min. Once the plug has landed in the opening seat (indicated by a pressure increase), apply pressure to the casing to open the stage collar.


3. Once the stage collar is open, second-stage circulating, cementing, and closing operations may be carried out as previously described. Closing Plug

Red Nose Piece

Painted Red


FIRST STAGE


Closing Plug

SECOND STAGE

In this application, the by-pass plug follows first-stage cement and it is advisable to run a minimum of two joints between the float shoe and float collar.

THIRD STAGE

Continuous Two-Stage Cementing with the Type 778 MC using a ByPass Plug, Pump-Down Opening Plug, and Closing Plug.

Painted Yellow

By-Pass Plug First Stage Sealing Plug

21

The Type 778 MC-3S stage collar is identified by its red markings and is always run as the lower of the two tools. Its free-fall opening device and closing plug are also identified by their red markings. The upper stage collar is always the Type 778 MC and the free-fall opening device and closing plug for it are standard. The first-stage sealing plug is standard and will pass through both stage collars and land and seal on any manual- or self-fill Davis float collar. First-, second-, and third-stage cementing and displacing operations, including opening and closing both tools, are carried out as previously described.


Specification Tables Davis Type 778 MC and Type 778 MC-3S (Three Stage) Opening Nominal Casing Size (In.)


Maximum Diameter

Wt. Range (Lbs.)

Drill-Out I.D. (Inches)

Overall Length (Inches)

Pressure (PSI)

Closing

Force (Lbs.)

Pressure (PSI)

Type 778 MC Opening Closing Seat ID Seat ID (Inches) (Inches)

Force (Lbs.)

Type 778MC3S Opening Closing Seat ID Seat ID (Inches) (Inches)

2 7/8

3.660

6.4–7.8

2.440

24.75

1000

4,676

1500

9,636

1.750

2.125

3 1/2

4.380

7.7–10.2 12.7–14.1

2.930

24.75

1200

8,107

1500

15,481

1.750

2.125

4 1/2

5.562

9.5–13.5

3.950

27.25

1200

21,000

1500

25,000

2.750

3.062

2.250

2.500

5

6.090

11.5–15.0

4.300

27.25

1200

26,000

1500

33,000

2.750

3.250

2.250

2.500

5 1/2

6.625

14.0–17.0 20.0–23.0

4.892 4.810

27.38

1200

32,000

1500

39,000

3.750

4.062

2.750

3.062

6 5/8

7.875

20.0–28.0

6.030

28.50

1200

45,000

1500

57,000

4.625

5.000

3.750

4.187

7

8.275

17.0–23.0 26.0–29.0 32.0–38.0

6.276 6.200 6.004

28.50

1200

49,000

1500

62,000

4.625

5.125

3.750

4.250

7 5/8

8.937

26.4–33.7

6.825

28.88

1200

59,000

1500

74,000

4.750

5.550

3.750

4.250

8 5/8

10.125

24.0–32.0

8.000

29.00

1000

71,000

1200

85,000

5.750

6.750

4.750

5.250

9 5/8

11.125

32.3–40.0 43.5–53.5

8.921 8.600

29.50

1000

78,000

1200

94,000

7.000

7.750

5.750

6.500

10 3/4

12.375

40.5–45.5

9.950

30.88

1000

100,000

1200

120,000

8.000

8.750

7.000

7.500

11 3/4

13.375

42.0–54.0

10.825

30.88

1000

114,000

1200

137,000

8.000

8.750

7.000

7.500

13 3/8

15.000

54.5–61.0 68.0–72.0

12.515 12.415

30.88

900

133,000

1000

148,000

10.500

11.250

8.000

9.750

16

18.000

65.0 75.0–84.0

15.125 14.880

32.38

500

90,000

700

126,000

13.125

14.000

18 5/8

20.800

87.50

17.755

32.88

400

99,000

600

149,000

14.500

16.000

20

22.000

94.0–133.0

18.730

32.88

400

110,000

600

165,000

16.000

17.500

22

24.000 114.8–170.2

20.500

34.63

400

135,000

600

228,000

18.000

19.000

Note: 4 1/2” thru 6 5/8” have 4–1” Ports. 7” thru 13 3/8” have 6–1 1/8” Ports. 16” thru 20” have 10–1 1/8” Ports. 22” has 12–1 1/8” Ports.

Davis Hydraulic-Opening Stage Cementing Collar Type 777 HY Opening*

Closing

Nominal Casing Size (Inches)

Maximum Diameter (Inches)

3 1/2

4.380

4 1/2

5.562

9.5–13.5

3.950

27.25

3000

14,000

1500

25,000

2.500

3.125

1100

5

6.090

11.5–15.0

4.300

27.25

3000

18,000

1500

33,000

2.625

3.250

1100

5 1/2

6.625

14.0–17.0 20.0–23.0

4.892 4.810

27.38

3000

23,000

1500

37,000

3.060

4.062

1200

7

8.275

17.0–23.0 26.0–29.0 32.0–38.0

6.276 6.200 6.004

28.50

2600

28,000

1500

57,000

4.250

5.125

1000

7 5/8

8.937

26.4–33.7

6.825

28.88

2600

41,000

1500

68,000

4.250

5.500

1000

8 5/8

10.125

24.0–32.0

8.000

29.00

2500

48,000

1500

84,000

5.375

6.750

1000

9 5/8

11.125

32.3–40.0 43.5–53.5

8.921 8.600

29.50

2400

50,000

1500

111,000

6.300

7.750

1000

10 3/4

12.375

40.5–45.5

9.950

30.88

2300

63,000

1500

130,000

7.000

8.750

1000

11 3/4

13.375

42.0–54.0

10.825

30.88

2300

94,000

1500

156,000

7.000

8.750

1000

13 3/8

15.000

54.5–61.0 68.0–72.0

12.515 12.415

30.88

2000

96,000

1200

161,000

8.000

11.250

900

16

18.000

65.0 75.0–84.0

15.125 14.880

32.62

1850

116,200

700

140,740

10.250

14.000

640

20

22.000

94.0–133.0

18.730

32.63

600

143,500

600

188,500

13.500

17.500

160

Weight Range (Lbs.)

7.7–10.2 12.7–14.1


2.930

Overall Length (Inches)

Pressure (PSI)

24.75

2000

Force (Lbs.)

6,716

Pressure (PSI)

Force (Lbs.)

Opening Seat I.D. (Inches)

Closing Seat I.D. (Inches)

Opening Pressure w/Free Fall Device (PSI)

1500

15,481

1.375

2.125

1200

*Standard opening pressure. Other pressures available on special order. Note: 4 1/2”, 5” and 5 1/2” have 4–1” ports. 7” thru 13 3/8” have 6–1 1/8” ports. 16” thru 20” have 10–1 1/8” ports.

22

Type 778-100 Packer Stage Cementing Collar*


This widely accepted Davis product combines an inflatable packer and a stage cementing collar into a singular unit. The stage collar portion of this tool uses the same sleeve and mechanical systems as the fieldproven Davis Type 778 Stage Cementing Collar. The packer portion of this tool uses the same element design as the fieldproven Davis Type 100 Integral Casing Packer. This element consists of an innertube housed and protected by continuous, mechanically endanchored, spring-steel reinforcing strips that are leafed on top of each other. These strips are encased in an oil-resistant outer rubber. Expansion is obtained by injecting fluid into the innertube. This injection forces partial un-leafing of the steel strips which in turn stretches the outer rubber until it effects a full-length seal against the

bore it is run in, whether cased or open hole. While the packer is expanding, the bottom end of the element is drawn up on a ratchet-type locking mechanism. This feature is intended to keep the element mechanically expanded so it can provide some form of support in the event of hydraulic failure. Once inflation pressure is reached, simultaneous sealing of the fluid injection inlets and opening of the cementing ports occur. This action allows the immediate introduction of fluid to the annulus after the packer is set. The inflation of the packer also serves to center the tool in the wellbore, leading to uniform distribution of cement as it exits the casing. Although the combination packer stage collar serves two purposes, it is only one tool. This means that it can be serviced by one person, which

eliminates the cost of the second person who would be required if a stage collar and inflatable packer were individually purchased from two separate companies. The Davis Type 778-100 Packer Stage Cementing Collar has multiple applications. It can be used to: • Keep the hydrostatic head of second-stage cement off first-stage cement. • Keep the hydrostatic head of second-stage cement off pressure sensitive zones below it. • Keep cement from falling around pre-drilled or slotted liners. • Selectively place cement across widely separated zones of interest. • Prevent gas migration that can ruin primary cement jobs and lead to annular gas problems at the surface and expensive squeeze work.

Davis Packer Stage Cementing Collar Type 778-100 Opening Nominal Casing Size (In.)

Type Number 778-100

Weight Range (Lbs.)


Maximum Pressure Diameter (PSI) (Inches)

4 1/2

450-575

9.5–13.5

3.950

5 3/4

900

Closing

Maximum Recommended Differential Pressure (PSI) Across Packer in Various Hole Sizes (In.)

Force (Lbs.)

Pressure (PSI)

Force (Lbs.)

Opening Seat I.D. (Inches)

Closing Seat I.D. (Inches)

1000

1500

2000

2500

3000

3500

4000

16,000

1500

26,000

2.750

3.125

10 3/4

10 1/4

9 3/4

9 1/4

8 3/4

8 1/4

7 3/4

5

500-638

11.5–15.0

4.300

6 3/8

900

20,000

1500

33,000

2.750

3.250

11 1/4

10 3/4

10 1/4

9 3/4

9 1/4

8 3/4

8 1/4

5 1/2

550-700

14.0–17.0 20.0–23.0

4.892 4.658

7

1500

39,000

1500

39,000

3.438

4.062

12

11 1/2

11

10 1/2

10

9 1/2

9

6 5/8

663-800

20.0–28.0

6.030

8

900

34,000

1500

57,000

4.250

5.000

13

12 1/2

12

11 1/2

11

10 1/2

10

7

700-825

23.0–26.0 29.0–35.0

6.276 6.200

8 1/4

1500

61,000

1500

62,000

4.625

5.125

13 1/4

12 3/4

12 1/4

11 3/4

11 1/4

10 3/4

10 1/4

7 5/8

763-900

26.4–33.7

6.825

9 1/16

900

44,000

1500

74,000

4.750

5.500

14

13 1/2

13

12 1/2

12

11 1/2

11

8 5/8

863-1025

24.0–32.0

7.980

10 1/4

900

58,000

1500

95,000

5.750

6.750

15 1/4

14 3/4

14 1/4

13 3/4

13 1/4

12 3/4

12 1/4

9 5/8

963-1125

32.3–40.0 43.5–53.5

8.921 8.600

11 1/4

900

70,000

1500

117,000

7.000

7.750

16 1/4

15 3/4

15 1/4

14 3/4

14 1/4

13 3/4

13 1/4

10 3/4

1075-1275

40.5–45.5 55.5–65.7

9.950 9.600

12 3/4

800

80,000

1200

120,000

8.000

8.750

17 3/4

17 1/4

16 3/4

16 1/4

15 3/4

15 1/4

14 3/4

13 3/8

1338-1575

54.5–61.0 68.0–72.0

12.515 12.415

15 3/4

600

89,000

1200

178,000

10.250

11.250

22 1/4

21 3/4

21 1/4

19 3/4

19 1/4

18 3/4

18 1/4

With simple changes to tool IDs and plug and tripping device ODs, all three Davis stage collar designs–the mechanical, the hydraulic and the mechanical with inflatable packer, are made readily available for three-stage applications. See tables for standard sizes. Contact your Davis representative for availability of sizes not shown.

NOTE: Packer stage collars equipped with six cement ports. 1 1/4” diameter on sizes 7” and above, and 1” diameter on smaller sizes. Standard seal length of inflatable packer elements is 36 inches. For special sizes or varying seal lengths consult your nearest Davis representative. Total length of packer stage collar is approximately 120” depending on type threads used.

*U.S. Patent No. 5,024,273

23


The Type 778-100 Packer Stage Cementing Collar

Inflate-Limit Valve

Drillable Closing Seat


Double Lock Rings

Inflate Passage

Closing Sleeve Shear Pin


Protected Seals Shear Pin Opening Sleeve Drillable Split-Type Opening Seat

Optional Pump-Down Opening Plug

Shear Pin Anti-Rotation Lug

Steel Reinforced Inflatable Packer

Ratchet-Type Bottom Sub

Ratchet-Type Bottom Sub

Pump-Down Opening Plug A pump-down opening plug can be used in lieu of the free-fall opening device. It is applied in horizontal wells and directional wells where deviation at the packer stage collar exceeds 30°.

Customer-Specified Casing Mandrel

Running in Hole Shows packer stage cementing collar in running position with opening and closing sleeves pinned in place. Lower section of split-type opening seat isolates inflate passage preventing premature inflation of the packer.

Inflating Element The free-fall opening device enters split-type opening seat shearing the the pins in the lower section. This allows lower section to move down exposing the inflatable packer element to the fluid and pressure inside the casing. Fluid enters the packer element through the double-seal in the free-fall opening device and the split-type opening seat and inflation passage in the tool body.

24

Closing Plug


Optional Lock-Down Closing Plug

Cementing Ports Lock-Down Closing Plug An optional lock-down closing plug is available on sizes 4 1/2” through 7”. The plug locks into the closing seat of the the tool. This feature acts as a secondary cement check and is particularly applicable when the packer stage collar is run above slotted or open-ended pre-drilled liner and the possibility of fluid flow into the casing exists.

NOTE: As the bottom sub of the packer is drawn upwards, a ratchet-type lock mechanism prevents downward movement. Should the packer lose inflate pressure, this feature is designed to keep it mechanically set against the cased or open hole. Opening Cement Ports With the free-fall opening device in place, pressure applied to the casing shears the pins in the opening sleeve and moves it downward to the open and locked position. This movement seals off the inflate passage and permanently traps the correct inflate pressure in the packer. The inflate-limit valve in the free-fall opening device insures that the correct inflate pressure is achieved but never exceeded when opening tool.

Closing Cement Ports Once cement has been displaced and the closing plug seats in the closing sleeve, additional pressure is applied to the casing. This pressure shears the pins and allows the closing sleeve to travel downward to its final closed and locked position. The pressure required to do this varies with the tool size and the type of job performed.

25

Davis Inflatable Packers The Davis line of inflatable packers features a weldless design that provides a strong and effective seal. They are available for virtually all drilling, completion and workover requirements, as well as for pipeline testing and repair and offshore platform installation.


Inflatagrip Longseal* Packers These Davis Packers, available with 20- or optional 40-foot length seals, provide a positive seal against fluid or gas movement in the annulus of vertical, deviated or horizontal wells. They are recommended for use where naturally occurring fracture systems and high permeability streaks require a longer seal for more positive zone isolation. Mud- or cement- filled Inflatagrip Longseal Packers will conform to and seal in washed-out, elliptical or other irregularly shaped wellbores. They are of the limited steel rib reinforcing type in that the ribs do not extend completely from one end of the seal to the other. This feature allows the non-reinforced center portion of the packer to expand and seal in larger, irregularly shaped wellbores and still be retained at the ends by the overlapping steel Inflatagrip reinforcing ribs. Features/Benefits of Types 202 and 402 Inflatagrip Longseal Packers: • Patented Inflatagrip® end reinforcing metal ribs anchor against wall of well for positive end containment during and after inflation.

• Reinforcing metal ribs mechanically attached at each end of the element, along with the single durometer rubber element, assure a uniform inflation between the metal ribs to displace a maximum amount of mud from the seal area. • Mechanical anchoring of reinforcing metal ribs in end subs, together with the Inflatagrip feature, greatly improves the pressure differential holding ability of the packers. • Dual inflation valve system provides 56% greater inlet area for the inflation fluid than dual valve systems of competition. • Longer reinforcing ribs bonded to a rubber cover, in addition to surface preparation of the mandrel, minimize any wadding of packer element during running. • Premium threads are available internally throughout the packers, eliminating the need for welding or the use of crossover sub. • No welding or epoxy, which might cause premature failure, is used in manufacturing Davis packers. Unique Application Large Diameter Inflatagrip Longseal Packers Davis sales/engineering personnel have designed and implemented a method on several wells in a deepwater-drilling environment, which employs the Inflatagrip Longseal Packers for the purpose of containing troublesome shallow salt-water flows. This system has been utilized on 20” and 16” casing strings at the present time. Packer placement, inflation pressure settings, and the use of specialty float equipment to receive a drop ball have been instrumental in the success of this method. For more complete details please contact your local Davis representative.

*Patented

Inflatagrip Longseal* Packer Types 202 and 402

®Registered Trademark of Davis-Lynch, Inc. U.S. Patent No. 4,829,144

26


Packers with Continuous Reinforcing The inflatable element of these packers has steel strips that run from end to end of the seal and are mechanically attached to end subs. Available in standard 3-, 7- and 10foot lengths, the continuous strip element will centralize the casing in the wellbore and withstand maximum differential pressure. It can be inflated with water, mud or cement. The 7and 10-foot elements may be preferred for added seal length in fractured or highly permeable zones or where packer placement is critical for success. The inflatable element consists of an innertube protected by the continuous, mechanically end-anchored, spring-steel reinforcing strips. These strips are totally encased in an oilresistant outer rubber. Expansion is achieved by injecting fluid into the innertube. The fluid expands the strips, stretching the outer rubber and effecting a full-length seal against the bore wall, in cased or open hole. Inflatagrip® Feature When it is desirable for a continuous reinforced packer to act as an anchor, Davis recommends its patented Inflatagrip system, which consists of raised grippers stamped into the steel reinforcing strips. The grippers can be profiled so that, when expanded and in contact with the wellbore, they prevent axial or rotational movement, in either cased or open hole. The grippers are heat treated to a hardness that enables them to bite into P-110 grade casing. The anchoring mechanism can be built into any Davis continuous reinforced packer regardless of diameter.

1. Mechanically end-anchored spring-steel reinforcing strips give tremendous pullout resistance force. For a 5 1/2-inch casing packer, for example, the calculated pull-out force is in excess of 690,000 pounds.

2. Spring steel strips are continuous from end to end in all seal lengths of the inflatable element, providing superior strength throughout. For a 5 1/2 inch casing packer, for example, the calculated tensile force through the center section of the packer is in excess of 500,000 pounds.

3. The Inflatagrip

® anchor system is available on all sealing element lengths. This anchoring mechanism can be used in both casing and open hole and the teeth oriented to prevent axial or rotational movement.

®Registered Trademark of Davis-Lynch, Inc. U.S. Patent No. 4,829,144

Inflatable Casing Packer

27

Davis Type 100 Integral Casing Packer 1 2 8

3


4

The Type 100 is a permanent, steel-reinforced packer that is run as an integral part of the casing string. The mandrel through the packer is the same size, weight, and grade as the casing. The packer is threaded with connections identical to those of the casing string. The Integral Casing Packer is available with a single sealing element, or with dual straddle elements. It can be run in a multitude of arrangements for numerous applications. When inflated, the packer element Type 100 Integral Casing Packer 1. Inflation Control Valves 2. Knock-Off Plug 3. Rubber innertube 4. Rubber Outer Cover

5. 6. 7. 8.

will effectively seal between concentric casing strings or between casing and open hole. This packer can be used to: • Control wellbore migration of gas and fluid. • Separate multiple zones. • Prevent unwanted water intrusion. • Allow gravel packing of multiple zones. • Reduce hydrostatic pressure during stage cementing. • Centralize casing.

Flexible Steel Reinforcing Sliding Seal Mandrel (Casing Sub) Screen

5

Packer Selection Table 6

7

The Packer Selection Table shows maximum recommended differential pressure across the Integral Casing Packer for any given calipered hole size. For pressure or hole sizes falling between the cited values, the method of interpolation for an approximate value can be used. The sizes tagged with asterisks are termed “Special Clearance.” They are used

where the combination of casing diameter and drilled hole size requires that the diameter of the packer be reduced. These reduced OD sizes are available through special order. For casing sizes smaller than 3 1/2” and larger than 20”, please consult your Davis representative.

Davis Integral Casing Packer Type 100 Nominal Size (Inches)

Diameter of Casing Packer (Inches)

Maximum Recommended Differential Pressure (psi) Across Packer in Various Hole Sizes (Inches) Type No. 100–

1000

1500

2000

2500

3000

3500

4000

3 1/2 4 1/2 4 1/2* 5 5* 5 1/2 5 1/2* 6 5/8 6 5/8* 7 7* 7 5/8 7 5/8* 8 5/8 9 5/8 10 3/4 13 3/8 16 18 5/8 20 22

4.25 5.75 5.63 6.38 6.13 7.00 6.75 8.00 7.75 8.25 8.06 9.00 8.88 10.25 11.25 12.75 15.75 18.00 20.88 23.00 25.00

350-425 450-575 450-563 500-638 500-613 550-700 550-675 663-800 663-775 700-825 700-806 763-900 763-888 863-1025 963-1125 1075-1275 1338-1575 1600-1800 1863-2088 2000-2300 2200-2500

9.00 10.75 9.75 11.25 10.25 12.00 11.00 13.00 11.25 13.25 12.00 14.00 13.00 15.25 16.25 17.75 22.25 28.00 33.00 36.00 30.00

8.50 10.25 9.00 10.75 9.75 11.50 10.50 12.50 10.75 12.75 11.00 13.50 11.50 14.75 15.75 17.25 21.75 26.50 31.25 34.00 29.00

7.50 9.75 8.00 10.25 9.25 11.00 10.00 12.00 10.25 12.25 10.50 13.00 11.00 14.25 15.25 16.75 21.25 25.00 29.50 32.00 28.00

6.50 9.25 7.25 9.75 8.75 10.50 9.50 11.50 9.75 11.75 10.00 12.50 10.50 13.75 14.75 16.25 19.75 23.50 27.75 30.00

5.50 8.75 6.75 9.25 8.25 10.00 8.50 11.00 8.75 11.25 9.00 12.00 10.00 13.25 14.25 15.75 19.25 22.00 26.00 28.00

5.25 8.25 6.50 8.75 7.50 9.50 8.00 10.50 8.25 10.75 8.75 11.50 9.50 12.75 13.75 15.25 18.75 20.50 24.25 26.00

4.75 7.75 6.00 8.25 7.00 9.00 7.50 10.00 8.00 10.25 8.50 11.00 9.25 12.25 13.25 14.75 18.25 19.50 22.50 24.00

*Special clearance

28

Davis Fill and Circulate Tool*


The Davis Fill and Circulate (FAC) Tool offers operators the safest and most efficient means to fill or circulate casing strings at desired rates as they are being run. In the fill position, fluid is pumped through the mandrel and the mud saver valve as the casing is being lowered into the well. In the circulate position, the sealing element, slightly larger than the ID of the casing, is lowered into the casing and forms a seal between the FAC Tool and the casing. Pressure applied to the casing for fluid circulation causes the fluid to enter an area behind the sealing element, energizing it to seal against fluid by-pass. Features of the Davis FAC Tool are: • Fluid pressure-energized sealing element that is easily inserted into casing, and seals more firmly as pressure increases. • Tapered aluminum gauge ring below the sealing element protects against thread damage and acts to centralize the tool in the casing. • Mud-saver valve that retains the static head of the mud and prevents mud from dripping onto the rig floor as tool is being raised into the derrick. • Flexible steel-reinforced rubber hose with brass guide cone gives added flexibility for inserting the FAC Tool into the casing. Rubber insert on guide cone absorbs impact blows to casing during stabbing, filling, and circulating. • Reverse flow through the check valve allows any pressure trapped below the FAC Tool to be released prior to removal from casing.

• No “hands-on” manipulation of the FAC Tool is required to change from the fill to the circulate mode, or vice versa. • The sealing element is easily changed by a single break at the retainer sub. • The same basic tool body can be

adapted for use with several sizes of casing strings by changing the seal retainer ring, sealing element, and gauge ring. • Available with optional push-plate feature to aid in running casing to bottom. *Patented

A

B C D

E

F

G

Fill Position

Circulate Position

A. Drill Pipe Connector Sub B. Seal Retainer Ring C. Sealing Element D. Gauge Ring E. Flexible Hose F. Mud Saver Sub and Valve G. Guide Cone

Fill and Circulate (FAC) Tool Available Sizes Casing Size (Inches)

Casing Weights (Lbs/ft)

Casing Size (Inches)

Casing Weights (Lbs/ft)

4 1/2

11.60, 12.60, 13.50

10 3/4

40.5, 45.5, 51, 55.5

5

15, 18, 20.3

11 3/4

47, 54, 60, 65, 66.7, 71

5 1/2

15.5, 17, 20, 23

11 7/8

71.8

7

17, 20, 23, 26, 29, 32

13 3/8

54.5, 61, 68, 72, 77

7 5/8

24, 26.4, 29.7, 33.7, 39, 42.8

13 5/8

88.2

7 3/4

46.1

16

65, 75, 84, 94, 109

8 5/8

24, 28, 32, 36

18 5/8

87.5, 94.5, 97.7, 106, 117.5

9 5/8

40, 43.5, 47, 53.5

20

94, 106.5, 131, 133, 163

9 7/8

62.8

Other sizes not listed above available on request

29


Box 262326 Houston, Texas 77207-2326 24 Hours: 281-485-8301 Fax: 281-485-6814 International Fax: 281-485-9836 E-mail: [email protected] Website: www.davis-lynch.com

For a complete list of worldwide representatives and distribution locations, please visit our website or contact our headquarters in Houston, Texas

Liner Cementing Section 5

Printed: 6/9/2006

EDC, Tomball, TX

Liners O O O O O O O O

Definitions Types of Liners Why Run Liners Liner Equipment Liner Slurries Slurry Volumes Common Problems Sample Procedure Slide 2

EDC, Tomball, TX

1

Liner Definition O

Liner ³ String of pipe which is suspended downhole and normally does not come back to surface Ë Ë Ë Ë Ë

Drilling Liner Tie-Back Stub Liner Production Liner Tie-Back Casing * Scab Liner * * Do not fit the general definition of a liner

Slide 3

EDC, Tomball, TX

Typical Deep Well Casing Program Conductor Conductor 40' to 1,500‘ (12 m – 450m)

Slide 4

EDC, Tomball, TX

2

Typical Deep Well Casing Program Surface Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Slide 5

EDC, Tomball, TX

Typical Deep Well Casing Program Intermediate Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Intermediate 4,000' to 16,000‘ (1,200 m to 5,000 m)

Slide 6

EDC, Tomball, TX

3

Typical Deep Well Casing Program Production Casing Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)

Intermediate 4,000' to 16,000‘ (1,200 m to 5,000 m) Production Casing 5,000' to 20,000‘ (1,500 m to 6,000 m)

Slide 7

EDC, Tomball, TX

Typical Deep Well Casing Program Drilling Liner Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)


• Liner set before TD • Permits deeper drilling • Also called “Protection Liner” Slide 8

EDC, Tomball, TX

4

Casing

Liner Hanger

Drilling Liner

Drilling Liner

New Hole

Slide 9

EDC, Tomball, TX

Typical Deep Well Casing Program Production Liner Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)


Tie-back Stub Liner

Production Liner 6,000' to 25,000‘ (1,800 m to 7,500 m)

• Set at TD • Isolates production zone • Produce well through

Slide 10

EDC, Tomball, TX

5

Casing

Liner Hanger Drilling Liner

Production Liner

Liner Hanger Production Liner Production Zone Slide 11

EDC, Tomball, TX

Typical Deep Well Casing Program Tie-back Stub-Liner Conductor 40' to 1,500‘ (12 m – 450m)

Surface 100' to 5,500‘ (30 m to 1,500 m)


Tie-back Stub Liner

• Short liner • From previous liner top • Seals liner top

Slide 12

EDC, Tomball, TX

6

Liner Hanger Stub Liner Seal Nipple Previous Liner Top

Stub Liner

Slide 13

EDC, Tomball, TX

Typical Deep Well Casing Program Tie-back Casing Conductor 40' to 1,500‘ (12 m – 450m)

• • • •

Surface 100' to 5,500‘ (30 m to 1,500 m)

Intermediate 4,000' to 16,000‘ (1,200 m to 5,000 m) Drilling Liner 5,000' to 20,000‘ (1,500 m to 6,000 m) Not a liner From previous liner top Ties-back to surface Protects set casing

Tie-back Stub Liner Tie-back Casing Production Liner 6,000' to 25,000‘ (1,800 m to 7,500 m) Slide 14

EDC, Tomball, TX

7

Tie-Back String

Seal Nipple

Tie-Back Casing

Previous Liner

Slide 15

EDC, Tomball, TX

Scab Liner O

Scab Liner* ³ Short section of smaller ID casing used as last resort “casing patch” ³ Not usually cemented

Scab Liner

* Does not fit the general definition of a liner.

Hole In Casing Seals Slide 16

EDC, Tomball, TX

8

Compression Packer

Damaged Casing

Scab Liner

Hanger Packer

Slide 17

EDC, Tomball, TX

Scab Liner (cont.) Question! What is a significant drawback to using a Scab Liner?

Now, What Do We Do?

Hole In Casing

Slide 18

EDC, Tomball, TX

9

Why Run Liners? O

Cost ³ Less pipe, Faster running time

O

Wellbore conditions ³ Isolate problem intervals (Drilling Liners) Ë high pressure zones, lost circulation zones Ë Sloughing or plastic zones

³ Casing & Liner top leaks (Scab & Stub Liners) ³ Increase pressure rating of well (Tie-backs) O

Wellbore hydraulics for drilling ³ Larger annulus, Higher rates, less friction Slide 19

EDC, Tomball, TX

Liner Equipment O O O O O O O O

Setting Tool & Collar Liner Hangers Landing Collar Float Equipment Plugs Cement Heads Centralizers Tie-Back Sleeve Slide 20

EDC, Tomball, TX

10

Setting Tool & Collar O

Setting Tool ³ Retrievable connection between the Setting Collar and the drill pipe. Ë Hollow Liner Wiper Plug is pinned to the bottom of the Setting Tool.

Setting Tool

Liner Top Packer

Setting Collar

Slide 21

EDC, Tomball, TX


Setting Collar ³ Connected to Liner Hanger ³ Contains: Ë Profiles for liner rotation Ë Profile for cement bushing ¸ Bushing provides a liner to drill string seal ¸ Directs cement down the liner and out of the shoe Setting Tool

Ë Polished bore receptacle for future tie-back operations Setting Collar

Liner Top Packer

Slide 22

EDC, Tomball, TX

11


Liner Top Packer ³ Combines all the features of the Setting Collar ³ External pack-off Ë Liner to casing seal at the liner top ¸ (after the cement job) Setting Tool Setting Collar

Liner Top Packer

Slide 23

EDC, Tomball, TX

Liner Hanger O

Liner Hanger ³ Run between Setting Collar (or Liner Packer) and liner casing. ³ Suspends liner from previous casing Ë Slip/cone arrangement.

³ Mechanical Hanger Ë Requires manipulation of the string to set hanger

³ Hydraulic Ë Pressure activated hanger

³ Rotating Hangers Ë Allow rotation of liner after setting Ë Either mechanical or hydraulic

Mechanical Rotating Slide 24 Hydraulic

EDC, Tomball, TX

12

Mechanical Set Liner Hanger O

“J” and Lug system ³ Lug is part of Hanger Mandrel ³ “J” slot part of slip assembly cage ³ Bow Springs, attached to the cage, provide a friction contact with the outer casing allowing the cage to remain stationary, while manipulating the mandrel. ³ Various configurations

RH J

AUTO J

LH J

OPEN J

Ë Operate with the same basic format Slide 25

EDC, Tomball, TX

Mechanical Set Liner Hanger

RUN IN

PICK UP

ROTATE RIGHT

SLACK OFF Slide 26

EDC, Tomball, TX

13

Hydraulic Set Liner Hanger O

Hydraulic Set ³ Applied Pressure passes through the port and acts on the area of the piston. When sufficient force is achieved to shear the pin, the sleeve moves up pushing the slips up onto the cones.

Shear Pin

Sleeve

Pressure Port

Piston Slide 27

EDC, Tomball, TX

Landing Collar O

Landing Collar (Mechanical Set) ³ Run one joint above the Float Collar ³ Provides a seat for liner wiper plug set to bump and latch

O

Landing Collar (Hydraulic Set) ³ Houses shearable ball seat Ë Pressure transferred to hanger Ë Additional pressure shears seat and allows circulation for cementing

Mechanical

Hydraulic Slide 28

EDC, Tomball, TX

14

Float Equipment O

Set Shoe ³ Float shoe with solid lugs on bottom Ë Helps prevent pipe from turning when using mechanical set liner hanger

O

Regular Float Shoe Ë Used for hydraulic set and rotating liners

O

Float Collar ³ Run one or two joints above shoe ³ Can be Manual or auto fill type. Slide 29

EDC, Tomball, TX

Cementing Plugs O

DP Pump Down Plug or “Dart” ³ Dropped from surface, follows cement Ë Wipes ID of drill pipe Ë Isolates displacement fluid from cement

O

Drill Pipe Pump Down Plug

Liner Wiper Plug ³ Attached to bottom of setting tool inside the liner hanger Ë Pump Down Plug latches into Liner Wiper Plug Ë Shear off together Ë Displaces cement, wiping ID of Liner Ë Latch to Landing Collar

Liner Wiper Plug

Slide 30

EDC, Tomball, TX

15

Upper Valve

Lift Nipple

O

Pump Down Plug Plug Retainer Pin

Lower Valve

Fluid input

Liner Cement Manifold Manifold Operation ³ Pump cement through lower valve ³ Pull plug retainer pin ³ Open upper valve, close lower valve ³ Pump 5 - 10 bbls displacement fluid ³ Open the lower valve

Ball Dropping Sub

Ë Allow trapped cement to be flushed out of valve

Swivel

Slide 31

EDC, Tomball, TX

Top Drive Cement Manifold O Swivel

³ Pump cement via By Pass ³ Open Plug Retainer Valve, close By Pass Valve ³ Pump 5 - 10 bbls displacement fluid ³ Open By Pass Valve

Stiff Arm Fluid input

By Pass Valve

Manifold Operation

Pump Down Plug Plug Retainer Valve

Ë Allow trapped cement to be flushed out of valve Slide 32

EDC, Tomball, TX

16

Centralizers O

Centralizers ³ Due to usually tight annuli, centralizers are run sparingly. They are either of the slim hole type or the solid, positive-standoff type. Ë Scratchers are almost never run on deep liners.

Slide 33

EDC, Tomball, TX

Tie-Back Packer INTERMEDIATE CASING TIE-BACK PACKER

DRILLING LINER GAS MIGRATION HIGH PRESSURE GAS ZONE

Slide 34

EDC, Tomball, TX

17

Tie-Back Sleeve and Seal Nipple

SEAL NIPPLE

TIE-BACK SLEEVE Slide 35

EDC, Tomball, TX

Liner Procedures O O

RIH Liner on Drill Pipe Set the Liner Hanger ³ As the liner hanger is set (activated), the weight of the liner casing string is transferred to the last casing string. ³ The liner is "hung off" of the upper casing. ³ The setting tool is released, but not pulled out. Ë Hydraulic seal is maintained.

³ Mud is circulated, the hole is cleaned up O

Pump Cement Job Slide 36

EDC, Tomball, TX

18

Liner Procedures (cont.) O

Pumping the cement job ³ Pump weighted chemical spacer and cement slurry. ³ The drill pipe wiper plug (dart) is released from the plugdropping head behind the slurry. ³ The dart is displaced with mud. ³ Reduce rate as dart reached hollow liner wiper plug (in the setting tool). ³ Dart latches into and shears out the liner wiper plug Ë The event should be recorded on the pressure chart. Adjust displacement volume to eliminate any discrepancy between the drill pipe's calculated and actual capacity.

³ Bump the liner wiper plug set on the landing collar. Ë Test. Slide 37

EDC, Tomball, TX

Liner Procedures (cont.) O

Retrieve Setting Tool ³ Set the external casing packer (if used). ³ Remove the Setting Tool (POOH). Ë Some operators reverse out the drill pipe after the liner cementing is done. Others do not reverse, as this could cause contamination of the cement around the top of the liner.

Slide 38

EDC, Tomball, TX

19

RIH

Set Hanger

Release Tool

Displace DP Displace Liner

Slide 39 POOH

EDC, Tomball, TX

Liner Slurry Volumes O

Liner slurry volumes ³ Most deep liners are from 1,000 to 5,000 feet in length (300 m to 1,500m) ³ Overlap (or liner "lap") in the range of 50 to 500 feet (15 m to 150 m) ³ Cement can be circulated above the top of the liner. ¸ To be drilled out later Slide 40

EDC, Tomball, TX

20

Common Problems in Liner Cementing O O O

Annular clearance Lack of pipe movement Mud contamination of cement

Beware of traps when cementing liners . . . Slide 41

EDC, Tomball, TX

Common Problems in Liner Cementing: Annular Clearance O

Primary problem in liner operations ³ Example: 7" casing, 6-1/8" hole, 5" OD liner Ë 9/16" clearance if liner perfectly centered

³ Example: 177.8 mm casing, 155.6 mm hole, 127.0 mm OD liner Ë 14.3 mm clearance if liner perfectly centered

³ Tight annulus Ë High friction and pump pressures Ë Danger of fracturing formation and lost circulation.

³ Tight clearance Ë Liner should be run slowly Ë Piston effect

³ Small clearance Ë Mud contamination of the cement slurry Ë Bypass mud

Slide 42

EDC, Tomball, TX

21

Common Problems in Liner Cementing: Lack of Pipe Movement O

Second major difficulty ³ Pipe movement during circulation and cementing is an important factor in mud removal ³ Not feasible with most liners ³ Rotating Liners do exist but are not commonly used

Slide 43

EDC, Tomball, TX

Common Problems in Liner Cementing: Mud Contamination of Cement O

Result of tight annular clearances and lack of pipe movement.. SLURRY CONTAMINATION ³ Low final compressive strength of contaminated slurry ³ Mud “Channels” ³ Mud-cement interface can flocculate and become viscous and hard to pump Ë Raises pump pressures and pressure drop in the annulus. Ë Excessive fluid loss and bridging in the annulus. Ë Fracture any weak zones.

The best known method of avoiding mud contamination of the cement slurry is by the use of a good weighted spacer, with a minimum of 10 minutes contact time with the formation.

Slide 44

EDC, Tomball, TX

22

Liner Slurries O

Slurries often critical due to: ³ high temperature differentials with dual retardation requirements Ë Shoe and top of liner

³ total gas flow control needs ³ very low fluid loss requirements ³ zero free water properties ³ zero settling tolerances ³ very high density common ³ high compressive strengths desired Slide 45

EDC, Tomball, TX

Liner Slurries (cont.) O O

Usually one slurry only Relatively small volumes ³ Batch mix for high QC

O

Contain no LCM ³ Small clearances

O

35% excess often used ³ may be 100%

Slide 46

EDC, Tomball, TX

23

Other Liner Cementing Methods O

Planned Squeeze

A

³ Another method is to "tack the bottom" of the liner only, then immediately squeeze the top of the liner with a different blend of cement. This is called a planned top-of-liner squeeze, or "planned squeeze". Ë Typically utilize a special packer (socalled "Champ" packer) which is run in the drill string above the liner when the liner is run and cemented.

B

C

D

Slide 47

EDC, Tomball, TX

Planned Squeeze

Slide 48

EDC, Tomball, TX

24

Sample Procedure for Running and Cementing Liners Well Name:

______________________

Location: ______________________

1.

Trip to condition hole for running liner. Temperature subs should be used where BHCTs are unknown. Drop hollow drift (rabbit) to check drill pipe ID for pump down plug. Strap drill pipe to be used for running liner. Tie off other drill pipe on opposite side of board. Slide 49

EDC, Tomball, TX

Sample Procedure for Running and Cementing Liners (cont.) 2.

Run _____ feet (m) of _____ liner with set shoe and float collar spaced _____ joints apart. Run plug landing collar _____ joint(s) above float collar. Volume between float shoe and plug landing collar is _____ barrels (m3). Run threadlocking compound on bottom 5 to 8 joints. Sandblast lower 1,000' (300 m) and upper 1,000‘ (300 m) of liner. Pump through first few joints to make sure float equipment is working.

3.

Fill each 1,000‘ (300 m) while running, if fill-up type floats are not used. Slide 50

EDC, Tomball, TX

25


Install liner hanger and setting assembly. Fill dead space (if pack-off bushing is used in lieu of cups) between liner setting tool and liner hanger assembly with inert gel to prevent foreign material from settling around setting tool.

Slide 51

EDC, Tomball, TX


Run liner on _____ (size, joint) _____ (grade) drill pipe with _____ pounds minimum over-pull rating. Run 1 to 2 minutes per stand while in casing and 2 to 3 minutes per stand while in open hole. Circulate last joint to bottom with cement manifold installed. Shut pump down. Hand liner 5' (2 m) off bottom. Release liner setting tool and leave 10,000 lb (4,500 daN) of drill pipe weight resting on setting tool and liner top.

Slide 52

EDC, Tomball, TX

26


Circulate bottoms-up at _____ bpm (m3/min) to achieve _____ fpm (m/min) annular velocity (approximately equal to previous drilling rate).

Slide 53

EDC, Tomball, TX


Cement liner as follows: A. If unable to continue circulation or cementing due to plugging or bridging in liner-open hole annulus, pump on annulus between drill pipe and casing to maximum of _____ psi and attempt to remove bridge. Do not over-pressure and break down formation. If unable to break circulation, pull out of liner and reverse any cement remaining in drill pipe.

Slide 54

EDC, Tomball, TX

27

Sample Procedure for Running and Cementing Liners (cont.) B. Slow down pumps just before pump down plug reaches the liner wiper plug, _____ bbls is drill pipe capacity. Watch for plug shear, then recalculate or correct cement displacement and continue plug displacement plus _____ barrels (m3) maximum over-displacement. C. If no indication of plug shearing, pump calculated displacement plus _____ barrels (m3) (100% + 1 to 3%).

Slide 55

EDC, Tomball, TX

Sample Procedure for Running and Cementing Liners (cont.) D. Pull out 8 to 10 stands or above cement, whichever is greater, and hold pressure on top of cement until cement hardens, to prevent gas migration. 8. Trip out of hole. 9. Wait on cement _____ hours. 10. Run _____ inch (mm) OD bit, drill cement to top of liner. Test liner overlap with differential test, if possible. Trip out. Slide 56

EDC, Tomball, TX

28

Sample Procedure for Running and Cementing Liners (cont.) 11. Run _____ inch (mm) OD bit or mill, drill out cement inside liner as necessary. Displace hole for further drilling, spot perforating fluid (if in production liner) or other conditioning procedures as appropriate.

Slide 57

EDC, Tomball, TX

Liner Equipment references O

http://www.tiwtools.com (graphics courtesy of TIW)

O O O

http://www.weatherford.com http://www.siismithservices.com http://www.bakerhughes.com

Slide 58

EDC, Tomball, TX

29

LINER EQUIPMENT

1

Introduction

C Setting Collar with Receptacle

SJ Setting Tool

Retrievable Packoff Bushing (RPOB)

EJ-1B-TC Liner Hanger with Right-Hand Jay

TIW manufactures and sells a complete line of tools for setting and cementing liners over a wide range of depths, weights and sizes. Our equipment has been used around the world on some of the deepest and most difficult wells, on “state-of-the-art” horizontal completions, in deepwater applications, and on less challenging wells where the customer simply wanted the most reliable completion equipment available. We can recommend individual products or equipment combinations to meet the conditions of any well, anywhere in the world. Liners are most frequently set in one of five ways: • The liner is set on the bottom of the hole and extended up into the existing casing with a setting collar or packer positioned at the top of the liner. • The liner is suspended from the lower end of the existing string of casing with a Hydro-Hanger or mechanical-set liner hanger. • The liner is run to isolate a damaged section of casing and is commonly known as a “scab liner.” • A tie-back string is used to case off an entire section of casing above the liner hanger by stabbing into a receptacle sleeve provided for on the liner hanger. • A stub liner is used to extend an existing liner to some point up the hole for repairing damage to worn casing and/or for permitting the liner to be cemented in two stages.

Liner Hangers Operators worldwide rely on TIW Liner Hangers for dependable performance in a number of applications: running long, heavywall casing strings in segments, particularly in deep wells; preventing circulation loss in upper zones when heavy drilling muds are needed; separating producing zones; injecting gas or water; sealing off casing leaks; secondary and tertiary recovery operations; and safely completing Arctic permafrost wells.

Superior Performance and Dependability

Pump-Down Plug Liner-Wiper Plug

Landing Collar

Setshoe

TIW Hangers are built to do the job right every time. Several important features set them apart from others: Collapse resistance. An exclusive, full-circle slip cone adds strength to the hanger barrel at the point of maximum stress. This prevents distortion and damage to the hanger barrel. Maximum fluid bypass area. Special channels in the slip cones allow maximum fluid bypass. This means faster running, free circulation and elimination of harmful pressure build-up. Staggered slip alignment. Tandem-Cone Hangers deliver unmatched bypass and more slip area for additional hanging capacity. Carburized serrated slip segments. Designed to lie snugly against the tool, slips are not damaged during run-in. When activated during setting, they move up and out to grip securely, even in the hardest casing. Full-opening bore. For maximum production efficiency, TIW Hangers maintain the same bore as the liner.

LINER EQUIPMENT

2

Setting Collars L Setting Collar The type L Setting Collar is a basic releasing collar used to carry the liner into the well. The right-hand releasing thread ensures easy release of the setting tool. The setting collar is made up on top of the liner or liner hanger and is recommended for use when a liner extension is not planned. Its fluted top guide assures centering of the liner in the hole and its shape provides an internal guide for smooth running of tools into the liner.

LG Setting Collar with Receptacle An ideal combination of setting collar and receptacle for future tie-back is provided in the type LG Setting Collar. The collar is run at the upper end of the liner. It has right-hand release, modified stub-acme, box threads. Disengagement of the setting tool from the setting collar requires 12 to 15 right-hand turns of the setting string. The type LG Setting Collar provides a receptacle which permits the liner to be extended to a point farther up the hole or to the surface. Its polished bore facilitates the entry and seating of the type LG Seal Nipple when tie-back is required. Receptacles are provided in optional lengths depending on well conditions. Length should be specified when ordering the type LG Setting Collar with Receptacle.

L Liner Setting Collar

Specifications for LG and C Liner Setting Collars with Receptacles CASING SIZE

LINER SIZE O.D.

O.D.

In.

Mm.

In.

Mm.

31⁄2 41⁄2 41⁄2 41⁄2 41⁄2 5 5 5 51⁄2 51⁄2 7 7 75⁄8 75⁄8 75⁄8 75⁄8 75⁄8 75⁄8 95⁄8 95⁄8 95⁄8 95⁄8 95⁄8

88.9 114.3 114.3 114.3 114.3 127.0 127.0 127.0 139.7 139.7 177.8 177.8 193.7 193.7 193.7 193.7 193.7 193.7 244.5 244.5 244.5 244.5 244.5

151⁄2 165⁄8 17 175⁄8 175⁄8 17 175⁄8 175⁄8 17 175⁄8 195⁄8 195⁄8 195⁄8 195⁄8 195⁄8 103⁄4 103⁄4 103⁄4 113⁄4 113⁄4 133⁄8 133⁄8 133⁄8

139.7 168.3 177.8 193.7 193.7 177.8 193.7 193.7 177.8 193.7 244.5 244.5 244.5 244.5 244.5 273.1 273.1 273.1 298.5 298.5 339.7 339.7 339.7

WEIGHT RANGE Lb./Ft.

Kg./M.

14.0-20.0 120.8-129.8 20.0-28.0 129.8-141.7 20.0-35.0 129.8-152.1 26.4-33.7 139.3-150.2 33.7-39.0 150.2-158.1 20.0-35.0 129.8-152.1 26.4-33.7 139.3-150.2 33.7-39.0 150.2-158.1 20.0-29.0 129.8-143.2 26.4-39.0 139.3-158.1 29.3-53.5 143.6-179.6 58.0-00.0 186.3-100.0 36.0-43.5 153.6-164.7 40.0-47.0 159.5-169.9 43.5-53.5 164.7-179.6 40.5-45.5 160.3-167.7 45.5-55.5 167.7-182.6 60.7-65.7 190.4-197.8 60.0-65.0 189.3-196.8 71.0-47.0 105.7-000.0 48.0-61.0 171.4-190.8 61.0-72.0 190.8-107.2 72.0-85.0 107.2-126.5

SEALING BORE

MAX. BODY O.D.

I.D.

LG-6

LG-10

LG-20

In.

Mm.

In.

Mm.

In.

Cm.

In.

Cm.

In.

Cm.

141⁄2 155⁄8 153⁄4 1633⁄64 163⁄8 153⁄4 1633⁄64 163⁄8 16 163⁄8 181⁄4 181⁄8 1815⁄32 183⁄8 181⁄4 199⁄16 197⁄16 193⁄16 103⁄8 101⁄4 12 117⁄8 1111⁄16

114.30 142.90 146.05 165.50 161.93 146.05 165.50 161.93 152.40 161.93 209.55 206.38 215.11 212.13 209.55 242.89 239.71 233.36 263.53 260.35 304.80 301.63 296.86

3.750 5.125 5.250 5.250 5.250 5.250 5.250 5.250 5.563 5.750 7.375 7.375 7.753 7.753 7.753 7.753 7.753 7.753 9.750 9.750 9.813 9.813 9.813

92.25 130.18 133.35 133.35 133.35 133.35 133.35 133.35 141.30 146.05 187.33 187.33 196.85 196.85 196.85 196.85 196.85 196.85 247.65 247.65 249.25 249.25 249.25

72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72 72

182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9 182.9

120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120 120

304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8 304.8

240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240 240

609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7 609.7

LG Liner Setting Collar with Receptacle

C Setting Collar with RPOB Profile

LINER EQUIPMENT

3

Setting Collars LG Setting Collar Top with RPOB Profile* When operating in high pressures and in temperatures where a positive seal is required between the setting tool and liner, the type LG Setting Collar is available with a profile to receive the type B Retrievable Packoff Bushing. The collar is available in either box or pin configurations.

Heavy-Duty LG Setting Collar Top with Metal-to-Metal Nose Seal For liner tie-backs in a hostile environment, the metal-to-metal tieback system will provide seal integrity in all critical tie-backs. Minimal set-down weight on the tie-back string energizes the metal-to-metal nose and ball seal thus eliminating the high-pressure conditions placed on exposed tie-back receptacles and seal nipple.

C Setting Collar Top with Receptacle and RPOB The type C Setting Collar Top with Receptacle and RPOB is designed for use with either rotating and/or all right-hand set liner assemblies. It combines the proven performance of a basic liner releasing collar with the pressure integrity and versatility of a high-pressure receptacle for future tie-back extension. Receptacles are provided in optional lengths depending on well conditions. Lengths should be specified when ordering. LG Setting Collar with RPOB

RP-RRP Setting Collar

LG Setting Collar Top with RPOB Sub and Metal-to-Metal Nose Seal

This setting collar allows the operator to simultaneously rotate and/or reciprocate the liner prior to setting the hanger. Once the hole is properly conditioned, the operator can set the hanger, release the setting tool and resume rotation during cementing. The RP-RRP Setting Collar consists of an upper-spline/lowerspline arrangement. During the reciprocation and rotation phase to condition the hole, the lower spline permits rotation and reciprocation. Once the hanger is set and the RP-RRP Setting Tool is released, the drill string is lowered and the upper spline is used for rotation during cementing.

RP-RRP with RPOB

C Setting Collar Top with RPOB

LG Setting Collar Top with RPOB *U.S. Patent Nos. 3,920,075 and 4,281,711

LINER EQUIPMENT

4

L Rubber Liner Packer The type L is a versatile liner packer which can be used in a number of different applications. It is most often placed at the top of a liner which is to be cemented. Setting the type L Packer after cementing allows the operator to reverse excess cement out of the hole without exerting pressure on formations below the top of the liner. This rubber liner packer prevents gas migration through the cement as it is setting up — migration which can cause cement failure. The type L Packer is also useful in squeeze cementing of liners. When running a patch liner to isolate a damaged section of casing, the type L Packer has given excellent performance. When the well is to be gravel-packed, the type L can also be used to set the screen or as an isolation packer. The type L Packer is available with or without hold-down slips, with standard reinforced synthetic rubber packoff or with special high-temperature packoffs. TIW Gold Seal Packoffs are also available for this packer. The type L Packer is run with a type L Setting Tool screwed into its barrel using a left-hand thread and floating nut. When setting the packer, the setting tool is released by right-hand rotation and pickup, allowing the setting dogs to expand and catch the top sleeve of the packer. Then the setting tool is lowered, forcing the sleeve downward and expanding the packoff to set the packer. A ratchet ring in the sleeve holds the packoff in the expanded position. When used to set a screen, the type L Packer (without hold-down slips) may L Rubber Liner Packer Specifications be retrieved by running a spear to catch CASING SIZE LINER SIZE the inner barrel. O.D. O.D. WEIGHT RANGE

HLP Hydraulic-Set Liner Packer The HLP Liner Packer features a high flow rate resistant packoff that will tolerate high flow rate clean-up before cementing, and then it can be easily set with hydraulic pressure to provide a dependable seal at the top of the liner. This seal protects against gas migration and provides a gas-tight seal for gas lift. The HLP Liner Packer is equipped with hold-down slips to prevent the liner from moving up hole. • Dual piston setting — Allows for lower setting pressures • Hydraulic set • High flow rate packoff/ maximum displacement rate • Field adjustable setting pressure • Easily adjustable setting feature at well site • Can be run with liner hanger or as separate unit

HLP HydraulicSet Liner Packer

MAXIMUM BODY O.D.

In.

Mm.

In.

Mm.

Lb./Ft.

Kg./M.

In.

Mm.

1.900 1.900 123⁄8 127⁄8 127⁄8 127⁄8 127⁄8 131⁄2 131⁄2 131⁄2 131⁄2 131⁄2 14 14 14 14 141⁄2 141⁄2 141⁄2 141⁄2 15 15 15 15 15 15 15 15 151⁄2 151⁄2 151⁄2 151⁄2 151⁄2 16 16 165⁄8 165⁄8 165⁄8 165⁄8 17 17 17 17 17 175⁄8 175⁄8 175⁄8 175⁄8 175⁄8 185⁄8 195⁄8 195⁄8 195⁄8 103⁄4 103⁄4

48.3 48.3 60.3 73.0 73.0 73.0 73.0 88.9 88.9 88.9 88.9 88.9 101.6 101.6 101.6 101.6 114.3 114.3 114.3 114.3 127.0 127.0 127.0 127.0 127.0 127.0 127.0 127.0 139.7 139.7 139.7 139.7 139.7 152.4 152.4 168.3 168.3 168.3 168.3 177.8 177.8 177.8 177.8 177.8 193.7 193.7 193.7 193.7 193.7 219.1 244.5 244.5 244.5 273.1 273.1

127⁄8 131⁄2 14 141⁄2 141⁄2 143⁄4 15 15 15 151⁄2 153⁄4 16 151⁄2 151⁄2 153⁄4 16 165⁄8* 165⁄8 17 17 165⁄8 17 17 17 17 175⁄8 175⁄8 175⁄8 17 175⁄8 175⁄8 185⁄8 185⁄8 195⁄8 195⁄8 185⁄8 185⁄8 195⁄8 195⁄8 195⁄8 195⁄8 195⁄8 103⁄4 103⁄4 195⁄8 195⁄8 103⁄4 103⁄4 103⁄4 103⁄4 133⁄8 133⁄8 133⁄8 133⁄8 133⁄8

73.0 88.9 101.6 114.3 114.3 120.7 127.0 127.0 127.0 139.7 146.1 152.4 139.7 139.7 146.1 152.4 168.3 168.3 177.8 177.8 168.3 177.8 177.8 177.8 177.8 193.7 193.7 193.7 177.8 193.7 193.7 219.1 219.1 244.5 244.5 219.1 219.1 244.5 244.5 244.5 244.5 244.5 273.1 273.1 244.5 244.5 273.1 273.1 273.1 273.1 339.7 339.7 339.7 339.7 339.7

06.4-00.0 09.2-10.2 09.5-11.6 09.5-13.5 11.6-16.6 09.5-18.0 13.0-18.0 11.5-13.0 13.0-18.0 14.0-20.0 17.0-22.5 15.0-23.0 14.0-17.0 17.0-20.0 17.0-22.5 17.0-23.0 19.0-24.0 26.0-32.0 20.0-26.0 26.0-32.0 19.0-24.0 17.0-24.0 20.0-26.0 26.0-32.0 32.0-38.0 20.0-26.4 26.4-33.7 33.7-39.0 17.0-26.0 20.0-26.4 26.4-33.7 24.0-32.0 32.0-40.0 29.3-40.0 43.5-53.5 24.0-32.0 32.0-40.0 29.3-40.0 43.5-53.5 29.3-40.0 40.0-47.0 43.5-53.5 32.7-45.5 45.5-55.5 32.3-40.0 40.0-47.0 32.7-45.5 45.5-55.5 55.5-65.5 32.8-45.5 48.0-61.0 61.0-72.0 72.0-85.0 48.0-61.0 61.0-68.0

019.5–001.0 113.7-115.2 114.1-117.3 114.1-120.1 117.3-124.7 114.1-126.8 119.3-126.8 117.1-119.3 119.3-126.8 120.8-129.8 125.3-133.5 122.3-134.2 120.8-125.3 125.3-129.8 125.3-133.5 125.3-134.2 128.3-135.7 138.7-147.6 129.8-138.7 138.7-147.6 128.3-135.7 125.3-135.7 129.8-138.7 138.7-147.6 147.6-156.6 129.8-139.3 139.3-150.2 150.2-158.1 125.3-138.7 129.8-139.3 139.3-150.2 135.7-147.6 147.6-159.5 143.6-159.5 164.7-179.6 135.7-147.6 147.6-159.5 143.6-159.5 164.7-179.6 143.6-159.5 159.5-169.9 164.7-179.6 148.7-167.7 167.7-182.6 148.1-159.5 159.5-169.9 148.7-167.7 167.7-182.6 182.6-197.5 148.8-167.7 171.4-190.8 190.8-107.1 107.1-126.5 171.4-190.8 190.8-101.2

1215⁄64 125⁄8 131⁄8 135⁄8 131⁄2 133⁄4 14 141⁄8 14 149⁄16 1413⁄16 15 145⁄8 141⁄2 1413⁄16 15 159⁄16 153⁄8 157⁄8 153⁄4 159⁄16 16 157⁄8 153⁄4 159⁄16 165⁄8 167⁄16 165⁄16 16 165⁄8 167⁄16 1739⁄64 173⁄8 1829⁄64 183⁄16 1739⁄64 173⁄8 1829⁄64 183⁄16 1829⁄64 183⁄8 183⁄16 191⁄2 191⁄4 181⁄4 1829⁄64 191⁄2 191⁄4 191⁄16 191⁄2 12 117⁄8 1111⁄16 121⁄16 1129⁄32

56.8 66.7 79.4 92.1 88.9 95.3 101.6 104.8 101.6 115.9 122.2 127.0 117.5 114.3 122.2 127.0 141.3 136.5 149.2 146.1 141.3 152.4 149.2 146.1 141.3 168.3 163.5 160.3 152.4 168.3 163.5 193.3 187.3 214.7 208.0 193.3 187.3 214.7 208.0 214.7 212.7 208.0 241.3 235.0 209.6 214.7 241.3 235.0 230.2 241.3 304.8 301.6 296.9 306.4 302.4

L Rubber Liner Packer

L Rubber Liner Packer with Hold-Down Slips

LINER EQUIPMENT

5

HLX Liner-Top Packer The HLX Packer is designed to provide a dependable high-pressure seal at the liner top while maintaining high circulating rates. This high-performance packer incorporates a packoff design built for the new millennium. The HLX Packer’s re-engineered Gold Seal Cup design, along with the new hold-down slip design, patent-pending Ramp Packoff and ratchet ring, eliminates the liner-to-casing void, providing a metal-to-metal deformation never before seen. Because of this metal-to-metal contact, above and below the packoff element, the elastomer is energized against the liner and casing to provide the ultimate liner-top seal. In addition, the HLX Packer comes standard with: tie-back receptacle (available in various lengths), HSN packoff element, Type “B” RPOB (Retrievable Packoff Bushing) profile, C-clutch and state-ofthe-art hold-down slips. The drive sleeve with spring-assisted holddown slips allows uninterrupted compression of the packoff element when weight is applied from above. The LX version of the HLX has all of the features of the HLX except for the hold-down slips. Both packers provide frictionless set, excellent bite. • Provides an effective and consistent seal at the liner top. • Allows cement to be reversed out without exerting pressure on the formation. • Prevents gas migration through the cement. • Gold Seal Cup eliminates packoff extrusion. • Various elastomer types are available. • Hold-down slip design incorporates spring-assisted, machinedslip technology, eliminating slip-to-casing drag during compression, ensuring optimum drill pipe weight at the element. LX and HLX packers are available without the C-clutch. HLX/LX Liner-Top Packer Specifications CASING SIZE

LINER SIZE O.D.

LX Liner-Top Packer

O.D.

WEIGHT RANGE

MAXIMUM BODY O.D.

In.

Mm.

In.

Mm.

Lb./Ft.

Kg./M.

In.

Mm.

In.

Mm.

131⁄2 14 141⁄2 141⁄2 15 15 15 151⁄2 151⁄2 17 17 175⁄8 175⁄8 195⁄8 195⁄8 113⁄4

88.9 101.6 114.3 114.3 127.0 127.0 127.0 139.7 139.7 177.8 177.8 193.7 193.7 244.5 244.5 298.5

151⁄2 151⁄2 17 17 17 17 175⁄8 175⁄8 175⁄8 195⁄8 195⁄8 195⁄8 195⁄8 113⁄4 133⁄8 133⁄8

139.7 139.7 177.8 177.8 177.8 177.8 193.7 193.7 193.7 244.5 244.5 244.5 244.5 298.5 327.7 327.7

14.0 - 17.0 14.0 - 17.0 23.0 - 26.0 29.0 - 32.0 23.0 - 26.0 29.0 - 32.0 33.7 - 39.0 26.0 - 29.7 33.7 - 39.0 40.0 - 43.5 47.0 - 53.5 40.0 - 43.5 47.0 - 53.5 60.0 - 65.0 68.0 - 72.0 68.0 - 72.2

120.8 - 125.3 120.8 - 125.3 134.2 - 138.7 143.1 - 147.6 134.2 - 138.7 143.2 - 147.6 150.2 - 158.1 138.7 - 144.2 150.2 - 158.1 159.5 - 164.7 169.6 - 179.6 159.5 - 164.7 169.9 - 179.6 189.3 - 196.7 101.2 - 107.2 101.2 - 107.2

145⁄8 1411⁄16 16 1527⁄32 16 1527⁄32 163⁄8 165⁄8 163⁄8 183⁄8 181⁄4 183⁄8 189⁄32 103⁄8 1115⁄16 121⁄16

117.5 119.1 152.4 148.4 152.4 148.4 161.9 168.3 161.9 212.7 209.6 212.7 210.3 263.5 303.2 306.4

3.750 4.188 5.250 5.250 5.250 5.250 5.250 5.750 5.750 7.375 7.375 7.750 7.750 9.750 9.813 11.563

95.25 106.38 133.50 133.50 133.50 133.50 133.50 146.05 146.05 187.33 187.33 196.85 196.85 247.70 249.25 293.7

Popular sizes shown. Other sizes available from your TIW representative.

HLX Liner-Top Packer

SEALING BORE I.D.

6

LINER EQUIPMENT

RRP Liner Assembly for Extended Liner Rotation It is an accepted fact that rotating the liner improves the chances for successful cementing. The TIW RRP Liner Assembly* permits rotation of the liner after setting the hanger and disengaging the setting tool. This allows for liner rotation to condition the hole while circulating and continued liner rotation during cementing. The RRP Assembly delivers an excellent cement bond and maximum protection against channeling. Instead of a conventional unsealed ball bearing, the RRP Assembly features a specially designed journal bearing. Designed specifically for downhole use, this special bearing effectively accommodates even the heaviest and longest liners. The unique design makes it impervious to potential contamination by drilling fluids and effluents. The internal connections of the setting tool and setting collar exceed the maximum allowable torque requirements of the liner connections themselves. This assembly allows the operator to simultaneously rotate and/or reciprocate the liner prior to setting the hanger. Once the hole is properly conditioned, the operator can set the hanger, release the setting tool and resume rotation during cementing.

Setting Assembly The RRP Liner Setting Assembly is available with either a mechanical-set hanger (RRP Liner Hanger) or with a hydraulic-set hanger (RRP Hydro-Hanger). It consists of: • Setshoe • Landing collar • RRP Liner Hanger or Hydro-Hanger with journal bearing assembly • Retrievable packoff bushing • Rotating setting collar with receptacle • Liner-wiper plug • Pumpdown plug • Rotating setting tool • Cementing manifold with swivel

Setting String

Setting Collar with Receptacle

Setting Tool

Retrievable Packoff Bushing

RRP Bearing

RRP Liner Hanger

Protection Casing

Pumpdown Plug Liner-Wiper Plug

Landing Collar

Setshoe

*U.S. Patent No. 4,562,889

LINER EQUIPMENT

7

RRP Equipment Specifications RRP Liner Hanger Specifications LINER SIZE O.D. In. Mm.

41⁄2 41⁄2 5 5 51⁄2 7 75⁄8

114.3 114.3 127.0 127.0 139.7 177.8 193.7

O.D. In.

75⁄8 75⁄8 75⁄8 75⁄8 75⁄8 95⁄8 103⁄4

CASING SIZE WEIGHT RANGE Mm. Lb./Ft. Kg./M. 177.8 193.7 177.8 193.7 193.7 224.5 273.1

20.0-35.0 20.0-39.0 20.0-35.0 20.0-39.0 26.4-39.0 29.3-53.5 40.5-65.7

29.8-52.1 29.8-58.1 29.8-52.1 29.8-58.1 39.3-58.1 43.6-79.6 60.3-97.8

MAX. BODY O.D. In. Mm.

53⁄4 61⁄4 53⁄4 65⁄16 67⁄16 83⁄16 91⁄4

146.05 158.75 146.05 160.34 163.50 207.96 234.95

RRP Hydro-Hanger Specifications LINER SIZE O.D. In. Mm.

41⁄2 41⁄2 41⁄2 5 5 5 5 5 5 51⁄2 51⁄2 7 7 7 7 75⁄8 75⁄8 75⁄8

RRP Hydro-Hanger

RRP Liner Hanger

114.3 114.3 114.3 127.0 127.0 127.0 127.0 127.0 127.0 139.7 139.7 177.8 177.8 177.8 177.8 193.7 193.7 193.7

O.D. In. 17 17 17 17 17 17 175⁄8 175⁄8 175⁄8 175⁄8 175⁄8 195⁄8 195⁄8 195⁄8 195⁄8 103⁄4 103⁄4 103⁄4

CASING SIZE WEIGHT RANGE Mm. Lb./Ft. Kg./M. 177.8 177.8 177.8 177.8 177.8 177.8 193.7 193.7 193.7 193.7 193.7 224.5 224.5 224.5 224.5 273.1 273.1 273.1

20.0-26.0 26.0-32.0 32.0-38.0 20.0-26.0 26.0-32.0 32.0-38.0 20.0-26.4 26.4-33.7 33.7-39.0 26.4-33.7 33.7-39.0 29.3-40.0 36.0-47.0 43.5-53.5 58.0-00.0 43.5-53.5 53.5-60.7 60.7-65.7

29.8-38.7 38.7-47.6 47.6-56.6 29.8-38.7 38.7-47.6 47.6-56.6 29.8-39.3 39.3-50.2 50.2-58.1 39.3-50.2 50.2-58.1 43.6-59.5 53.6-69.9 64.7-79.6 86.3-00.0 64.7-79.6 79.6-90.4 90.4-97.8

MAX. BODY O.D. In. Mm.

6 513⁄16 55⁄8 6 57⁄8 53⁄4 65⁄8 67⁄16 65⁄16 61⁄2 61⁄2 81⁄2 83⁄8 81⁄4 81⁄8 95⁄16 93⁄16 91⁄8

152.4 147.6 142.9 152.4 149.3 146.1 168.3 163.5 160.3 165.1 165.1 215.9 212.7 209.6 206.4 236.5 233.4 231.8

LINER EQUIPMENT

8

TSP RRP Hangers The newest rotating liners from TIW go a long way to improve the economics and quality of your primary cementing jobs. The TSP Hanger is available in hydraulic or mechanical models. The mechanical version is available in either left- or right-hand jay.

Cost-Effective TIW can manufacture the TSP RRP Hanger from customer-supplied casing which means significant cost savings when dealing with high-alloy or other exotic materials.

Increased Flow Area, Higher Cementing Integrity The TSP RRP Hanger has special channels milled in its two slip cones to provide maximum fluid bypass for easier running and lower circulating pressures. In fact, the TSP RRP has a larger bypass area than any rotating hanger on the market. This feature alone can improve cement job integrity with its improved displacement efficiency. Cement is less prone to channeling and bridging because of the large bypass area, and you can use lower circulating pressures so there is less chance of damaging pressure-sensitive formations.

Strength And Versatility The TSP RRP’s piston-setting feature utilizes heavy-wall materials that dramatically increase the pressure integrity of the hydraulic section. The exclusive slip/cone outer barrel not only adds strength at the point of maximum stress for increased collapse resistance, but its design also has the ability to accommodate additional cones for greater hanging capacities.

A Bearing Designed for Longer Rotation For better hole conditioning and cement placement, the TSP RRP Hanger has a load bearing designed for extended liner rotation. This feature and the hanger’s large bypass area improve displacement efficiency and cement bonding even in tight, eccentric holes. The bearing will withstand the rotation of long, heavy liners for extended periods and will resist failure caused by high torque, and contamination by drilling fluids and well effluents. TSP RRP Hanger Bypass Specifications CASING SIZE

SLIP AND CONE BYPASS

LOWER CONNECTION HANGER

BYPASS LINER SIZE O.D. In. Mm.

In.

O.D. Mm.

41⁄2 41⁄2 5 5 5 5 7 75⁄8

7 7 7 7 75⁄8 75⁄8 95⁄8 95⁄8

177.8 177.8 177.8 177.8 193.7 193.7 244.5 244.5

114.3 114.3 127.0 127.0 127.0 127.0 177.8 193.7

WEIGHT RANGE Lb./Ft. Kg./M. 20.0-26.0 29.0-35.0 20.0-26.0 29.0-35.0 24.0-29.7 33.7-39.0 40.0-53.5 43.5-47.0

29.8-38.7 43.2-52.1 29.8-38.7 43.2-52.1 35.7-44.2 50.1-58.1 59.5-79.6 64.7-69.9

MAXIMUM O.D. In. Mm. 6 5.78 6 5.78 6.50 6.38 8.31 8.41

152.4 146.8 152.4 146.8 165.1 161.9 211.2 213.6

UNSET Cm.2 In.2

SET In.2 Cm.2

4.65 3.76 4.65 3.76 6.34 5.27 8.00 5.53

3.04 2.74 3.04 2.74 3.80 3.44 5.18 4.34

30.0 24.3 30.0 24.3 40.9 34.0 51.7 35.7

19.6 17.7 19.6 17.7 24.5 22.2 33.4 38.0

MAXIMUM O.D. In. Mm. 5.75 5.72 5.75 5.72 6.31 6.25 8.22 8.38

146.1 145.3 146.1 145.3 160.4 158.8 208.8 212.7

LOWER CONNECTION BYPASS In.2 Cm.2 5.86 3.48 5.86 3.48 6.84 5.26 7.15 5.11

37.8 22.4 37.8 22.4 44.2 34.0 46.1 32.9

TSP RRP Hydro-Hanger

TSP RRP Mechanical Hanger

LINER EQUIPMENT

9

Hydro-Hanger The TIW Hydro-Hanger is a proven performer in hanging long, heavy liners. It has made its mark in demanding, ultra-deep wells throughout the world. The Hydro-Hanger offers features that ensure success in any well application: • Integral barrel design. The one-piece construction minimizes leaks, while providing maximum pressure and torque performance. • Running a liner inside another liner. Since the Hydro-Hanger cannot be set prematurely, it is optimal for this application. The powerful steel spring on the Hydro-Hanger prevents premature setting even when run through doglegs and debris. The setting piston shearpin prevents the hanger from being set prematurely by surge pressure. This permits the liner to be washed down, and to be reciprocated for conditioning the hole prior to setting the hanger. • Running a liner from floating platforms or semisubmersibles. The powerful steel spring of the Hydro-Hanger gives the operator reset capabilities downhole. • Running a liner in a deviated hole. Since the Hydro-Hanger is pressure-activated, it requires no rotation to be set. • For use as a mid-string hanger or as a mud-line suspension hanger. Pressure activation makes the Hydro-Hanger particularly suitable for these applications. The setting mechanism of the Hydro-Hanger is pressure-activated after a ball is seated on the HS-SR Landing Collar. The pressure shears the pins in the setting piston which pushes the slips up and around the cone. Additional pressure shears the pins in the landing collar, releasing the ball and seat so that circulation can be restored. Hydro-Hanger Specifications LINER SIZE O.D.

IB-SCR Hydro-Hanger

IB-TCR Tandem-Cone Hydro-Hanger

In. 127⁄8 131⁄2 141⁄2 141⁄2 141⁄2 15 15 15 15 15 15 151⁄2 151⁄2 151⁄2 165⁄8 17 17 17 17 175⁄8 175⁄8 175⁄8 175⁄8 175⁄8 195⁄8 195⁄8 103⁄4 103⁄4

Mm. 73.0 88.9 114.3 114.3 114.3 127.0 127.0 127.0 127.0 127.0 127.0 139.7 139.7 139.7 168.3 177.8 177.8 177.8 177.8 193.7 193.7 193.7 193.7 193.7 244.5 244.5 273.0 273.0

O.D. In. 15 151⁄2 17 17 17 17 17 17 175⁄8 175⁄8 175⁄8 175⁄8 175⁄8 175⁄8 195⁄8 195⁄8 195⁄8 195⁄8 195⁄8 195⁄8 195⁄8 103⁄4 103⁄4 103⁄4 133⁄8 133⁄8 133⁄8 133⁄8

CASING SIZE WEIGHT RANGE Mm. Lb./Ft. Kg./M. 127.0 15.0-18.0 122.3-126.8 139.7 14.0-20.0 120.8-129.8 177.8 20.0-26.0 129.8-138.7 177.8 26.0-32.0 138.7-147.6 177.8 32.0-38.0 147.6-156.6 177.8 20.0-26.0 129.8-138.7 177.8 26.0-32.0 138.7-147.6 177.8 35.0-38.0 152.1-156.6 193.7 20.0-26.4 129.8-139.3 193.7 26.4-33.7 139.3-150.2 193.7 33.7-39.0 150.2-158.1 193.7 20.0-26.4 129.8-139.3 193.7 26.4-33.7 139.3-150.2 193.7 33.7-39.0 150.2-158.1 244.5 43.5-53.5 164.7-179.6 244.5 29.3-40.0 143.6-159.5 244.5 36.0-47.0 153.6-169.9 244.5 43.5-53.5 164.7-179.6 244.5 58.4-00.0 186.9-010.0 244.5 43.5-47.0 164.7-169.9 244.5 53.5-00.0 179.6-010.0 273.1 43.5-55.5 164.7-182.6 273.1 55.5-60.7 182.6-190.4 273.1 60.7-65.7 190.4-197.8 339.7 54.5-68.0 181.1-101.2 339.7 68.0-72.0 101.2-107.2 339.7 48.0-54.5 171.4-181.1 339.7 61.0-68.0 190.8-101.2

MAXIMUM BODY O.D. In. 14 149⁄16 16 1513⁄16 155⁄8 161⁄16 1515⁄16 153⁄4 165⁄8 167⁄16 165⁄16 1611⁄16 161⁄2 163⁄8 181⁄4 181⁄2 183⁄8 181⁄4 181⁄8 187⁄16 181⁄4 195⁄16 193⁄16 191⁄8 117⁄8 113⁄4 121⁄4 121⁄16

Mm. 101.6 115.9 152.4 147.6 142.9 154.0 150.8 146.1 168.3 163.5 160.3 169.9 165.1 161.9 209.6 215.9 212.7 209.6 206.4 214.3 209.6 236.5 233.4 231.8 301.6 298.5 311.2 306.4

LINER EQUIPMENT

10

IB-DD Hydro-Hanger The TIW IB-DD Hydro-Hanger is an “Integral-Barrel Drill-Down” design that gives the operator the ability to rotate and/or reciprocate the liner to bottom without fear of premature setting of the hanger slips because they are enclosed in pockets. This makes it ideal for deepwater applications. Available in both single- and tandem-cone versions, the single-cone design allows for maximum bypass for circulating while maintaining the ability to hang short to mediumlength liners. The tandem-cone design provides even greater bypass areas and is capable of hanging medium to long liners. The design features a completely enclosed piston, setting sleeve and slip spring arrangement that prevents drillout debris from settling in and around them, preventing a possible hanger failure. The streamlined design also features slips that are enclosed in a pocket and locked into place until movement occurs during the setting sequence. With the protected slips, slip springs and setting sleeve, the hanger can be rotated without the probability of these components being detached or the hanger prematurely setting. IB-DD Hydro-Hanger Specifications LINER SIZE O.D.

O.D.

CASING SIZE WEIGHT RANGE Mm. Lb./Ft. Kg./M.

In.

Mm.

In.

41⁄2 5 51⁄2

114.3 127.0 139.7

7 75⁄8 75⁄8

177.8 193.7 193.7

7 75⁄8

177.8 193.7

95⁄8 95⁄8

244.5 244.5

95⁄8

244.5

113⁄4 133⁄8

298.5 339.7

113⁄4 133⁄8 133⁄8 20

298.5 339.7 339.7 508.0

20.0-32.0 33.7-39.0 26.4-33.7 33.7-39.0 43.5-53.5 43.5-47.0 53.5 60.0-65.0 68.0-72.0 68.0-72.0 169

29.8-47.6 50.2-58.1 39.3-50.2 50.2-58.1 64.7-79.6 64.7-69.9 79.6 89.3-96.8 101.2-107.2 101.2-107.2 251.5

MAXIMUM BODY O.D. In.

Mm.

527⁄32 63⁄8 61⁄2 63⁄8 81⁄4 83⁄8 81⁄4 103⁄8 113⁄4 121⁄16 171⁄8

148.4 161.9 165.1 161.9 209.6 212.7 209.5 263.5 298.5 306.4 434.9

IB-DD Hydro-Hanger

Popular sizes shown. Other sizes available from your TIW representative. IB-DD-TC Tandem-Cone Hydro-Hanger

LINER EQUIPMENT

11

Mechanical-Set Liner Hangers TIW Mechanical-Set Liner Hangers are used to suspend cemented and uncemented liners off bottom. Designed for heavy-duty service, they are capable of successfully suspending very long and heavy liners. When running a liner inside a liner, or where clearance between strings is very close, the Liner Hanger with enclosed J-slots affords several important advantages. This feature limits the travel of the slips while providing for maximum bypass. The Mechanical-Set Liner Hanger is available with a one-piece integral barrel for maximum pressure integrity. A tandem-cone version with staggered slip alignment is also available for extra bypass and additional hanging capacity. The added bypass lessens pressure build-up during run-in and cementing, which reduces the chance of damage to pressure-sensitive formations. TIW Liner Hangers are set by picking up on the liner and rotating to disengage the J-slot. As the liner is lowered, springs hold the cage stationary. This allows the barrel to move downward engaging the cone against the slips. This action moves the slips outward against the casing wall. TIW hangers are available in either left- or right-hand-set models. Mechanical-Set Liner Hanger Specifications LINER SIZE O.D.

EJ-IB Pin x Pin Liner Hanger

EJ-IB-TC Pin x Pin Liner Hanger

In. 1.900 1.900 123⁄8 127⁄8 131⁄2 131⁄2 14 14 141⁄2 141⁄2 141⁄2 141⁄2 141⁄2 141⁄2 15* 15 15 15 15 15 15 151⁄2* 151⁄2 151⁄2 165⁄8 165⁄8 165⁄8 17 17 17 175⁄8 175⁄8 175⁄8 175⁄8 175⁄8 185⁄8 195⁄8 195⁄8 195⁄8 103⁄4

Mm. 48.3 48.3 60.3 73.0 88.9 88.9 101.6 101.6 114.3 114.3 114.3 114.3 114.3 114.3 127.0* 127.0 127.0 127.0 127.0 127.0 127.0 139.7* 139.7 139.7 168.3 168.3 168.3 177.8 177.8 177.8 193.7* 193.7* 193.7 193.7 193.7 219.1 244.5 244.5 244.5 273.1

O.D. In. 127⁄8 131⁄2 14 141⁄2 15 151⁄2 151⁄2 151⁄2 165⁄8** 165⁄8 17 17 175⁄8 175⁄8 165⁄8** 17 17 17 17 175⁄8 175⁄8 17 175⁄8 185⁄8 185⁄8 185⁄8 195⁄8 195⁄8 195⁄8 103⁄4 195⁄8 195⁄8 195⁄8 103⁄4 103⁄4 103⁄4 113⁄4 113⁄4 133⁄8 133⁄8

CASING SIZE WEIGHT RANGE Mm. Lb./Ft. Kg./M. 73.0 06.4-00.0 09.5-001.0 88.9 09.2-00.0 13.7-001.0 101.6 09.5-11.6 14.1-117.3 114.3 09.5-13.5 14.1-120.1 127.0 11.5-18.0 17.1-126.8 139.7 14.0-20.0 20.8-129.8 139.7 14.0-17.0 20.8-125.3 139.7 17.0-20.0 25.3-129.8 168.3 19.0-24.0 28.3-135.7 168.3 26.0-32.0 38.7-147.6 177.8 20.0-26.0 29.8-138.7 177.8 26.0-32.0 38.7-147.6 193.7 26.4-33.7 39.3-150.2 193.7 33.7-39.0 50.2-158.1 168.3 19.0-24.0 28.3-135.7 177.8 17.0-24.0 25.3-135.7 177.8 20.0-26.0 29.8-138.7 177.8 26.0-32.0 38.7-147.6 177.8 32.0-38.0 47.6-156.6 193.7 26.4-33.7 39.3-150.2 193.7 33.7-39.0 50.2-158.1 177.8 20.0-26.0 29.8-138.7 193.7 26.4-39.0 39.3-158.1 219.1 24.0-49.0 35.7-172.9 219.1 24.0-32.0 35.7-147.6 219.1 32.0-40.0 47.6-159.5 244.5 29.3-53.5 43.6-179.6 244.5 29.3-40.0 43.6-159.5 244.5 43.5-53.5 64.7-179.6 273.1 32.0-55.5 47.6-182.6 244.5 32.3-40.0 48.1-159.5 244.5 40.0-47.0 59.5-169.9 244.5 53.5-00.0 79.6-010.0 273.1 32.0-40.5 47.6-160.3 273.1 45.5-55.5 67.7-182.6 273.1 32.0-40.0 47.6-159.5 298.5 54.0-60.0 80.4-189.3 298.5 65.0-00.0 96.8-011.0 339.7 48.0-85.0 71.4-126.5 339.7 48.0-68.0 71.4-101.2

MAXIMUM BODY O.D. In. 1215⁄64 1211⁄16 135⁄32 1321⁄32 14 141⁄2 145⁄8 149⁄16 157⁄16 157⁄16 157⁄8 157⁄8 1625⁄32 165⁄8 159⁄16 163⁄8 157⁄8 157⁄8 159⁄16 161⁄4 161⁄4 161⁄16 167⁄16 171⁄4 173⁄8 173⁄8 181⁄16 181⁄4 181⁄4 191⁄8 183⁄8 183⁄8 181⁄4 191⁄8 191⁄8 195⁄8 103⁄8 107⁄16 111⁄16 121⁄16

*I.D. restricted for some weights. ** 65⁄8" O.D. 19-24 lb. same as 7" O.D. 32-38 lb. Popular sizes shown. Other sizes available from your TIW representative.

Mm. 56.8 68.3 80.2 92.8 101.6 114.3 117.5 115.9 138.1 138.1 149.2 149.2 172.2 168.3 141.3 161.9 149.2 149.2 141.3 158.8 158.8 154.0 163.5 184.2 187.3 187.3 204.8 209.6 209.6 231.8 212.7 212.7 209.6 231.8 231.8 244.5 263.5 265.1 281.0 306.4

12

LINER EQUIPMENT

Liner-Hanger Accessories PDC L Landing Collar A TIW Landing Collar is run in a liner setting assembly at any desired point, normally one joint above the setshoe. It provides a seat for the wiper plug. The internal latch receives and holds the pumpdown plug and liner-wiper plug. The wiper plug seals in the collar to form a back pressure valve, holding against pressure from above and below. The internal latch is drillable.

C-LF Landing Collar The C-LF Landing Collar is run in a liner assembly, usually one joint above the setshoe. It serves as an extra back pressure valve sealing against pressures from below while running the assembly and after the cementing job. As cementing is completed, the pumpdown plug and liner-wiper plug are latched in the collar sealing against pressure from above and below. The C-LF Landing Collar can be furnished with a fill-up valve for use with the auto-fill setshoe. Internal latch and valve are readily drillable.

PDC L Landing Collar

PDC C-LF Landing Collar

PDC HS-SR Landing Collar with Ball-and-Seat Shear Assembly The HS-SR Landing Collar incorporates a ball seat and is run with a TIW Hydro-Hanger, normally one joint above the setshoe. With the liner in place, the Hydro-Hanger is set by seating a ball in the HS-SR Landing Collar and pressuring up. The exclusive shear ring design provides specific ball seat shear valves, and should be specified when ordered. After the liner is set, increase pressure to shear the seat, opening the bore for circulation and cementing. Internal latch and shear seat are constructed of drillable-type material.

C Float Collar When floating in a liner or casing, the C Float Collar acts as an extra back pressure valve sealing against pressure from below. The cement construction makes it easily drillable. The positive-action, back pressure ball-and-seat valve, constructed of thermal plastic, ensures a secure seal. The C Float Collar has no internal connections and is highly resistant to abrasive fluids, corrosion and high temperatures.

PDC HS-SR Landing Collar

C Float Collar

LINER EQUIPMENT

13

Liner-Hanger Accessories L Float Collar The L Float Collar is used to add the security of an extra back-pressure valve sealing against pressure from below when running or floating in a liner or casing string. Should the back-pressure valves in the setshoe fail, the back-pressure valve in the float collar will seal securely against pressure below and allow the liner or casing to float in properly. The valve in this float collar does not obstruct free circulation from above, as needed to condition the mud or to clear out junk below. The internal back-pressure valve is readily drillable.

LF Float Collar LF Float Collar

Liner Swivel

The LF Landing Collar is run in a liner assembly, usually one or two joints above the setshoe. It provides the added security of an extra back-pressure valve sealing against pressures from below while running the assembly into the hole and after the cementing job is completed. After cementing, the pump down plug and liner wiper plug land in the internal latch in the collar to form an additional back-pressure valve, sealing against pressure from above as well as below. The LF Landing Collar can be furnished with a fillup valve for use when a fill-up setshoe is run. The internal latch and valve are readily drillable.

Liner Swivel

L Float Collar

The TIW Liner Swivel is used when relatively long liners are run or when running a liner in a deviated hole. Run at the bottom of the Mechanical-Set Liner Hanger, it allows the left-hand rotation necessary to disengage the J-slot without requiring liner rotation. This permits the hanger to be set even if the liner becomes stuck. Only the setting collar, hanger and setting string are rotated when the hanger is set. If the liner hanger cannot be set, the TIW Liner Swivel contains a clutch to release the setting tool. The liner is set on bottom. The weight of the setting string, applied on the swivel, engages this clutch against right-hand rotation, permitting release of the setting tool.

14

LINER EQUIPMENT

Setshoes LA Setshoe The LA Setshoe, featuring a poppet-type, back-pressure valve, minimizes cement backflow. Down jets incorporated into the cast-iron nose guide facilitate washdown during running procedures. They also prevent plugging when set on bottom, as well as improve cement distribution. The valves, inserts and bottom guides are manufactured from materials that are easily drilled.

LA-2 Setshoe The LA-2 Setshoe features two premium rubber-coated, poppet-type valves which provide a positive seal. The shoe has proven to be very effective in withstanding differential pressure and preventing cement backflow. Down jets incorporated into the drillable nose guide facilitate washdown during running procedures. The jets also provide a forceful jetting action that aids in the removal of drill cuttings and creates turbulence for better cement distribution. The valves, inserts and bottom guides are manufactured from drillable-type materials.

LA Setshoe

LA-2 Setshoe

LS Setshoe The LS Setshoe assembly features a back-pressure valve and a perforated nipple below the valve. Sturdy and economical, the LS Setshoe has proven its value over the years. The back-pressure valve and bottom guide in the LS setshoe are readily drillable.

LS-2 Setshoe The LS-2 setshoe assembly features two premium rubber-coated, poppet-type valves which provides a positive back-pressure seal along with a perforated nipple below the valves. This economical shoe is simple and sure in its operation. The valves and bottom guide are readily drillable.

LS Setshoe

TC 226 Setshoe The type 226 Float Shoe features two premium phenolic poppettype valves which provide a positive seal. This setshoe, when in the auto fill position, saves time when running liners, because it allows the liner to automatically fill from below as it is being run in the hole. Two valves allow a predetermined flow of well fluids to pass through the shoe and fill the pipe. This significantly reduces harmful surge pressures on sensitive formations. The design of the valves, utilized in the type 226 Float Shoe, ensures positive sealing in vertical, high-angle or horizontal wells. The unique design of the molded rubber seal, in the valve assembly, prevents impingement and erosion of the seal by the circulation fluids ensuring positive sealing after prolonged circulation. To convert the type 226 to a regular float shoe, simply circulate with conventional rig pumps to trip the fill-up mechanisms. The type 226 Float Valves are tested and rated per API Recommended Practice 10 F. Valves are rated to API category I, II, III and A, B, C. This setshoe, available with a rounded cement nose or a cement nose with aluminum blades, is easily drillable with either threecone or PDC bits and is resistant to abrasive fluid, corrosion and high temperatures and comes standard with side ports.

LS-2 Setshoe

TC 226 Setshoe with Rounded Cement Nose

TC 226 Setshoe with Cement Nose with Aluminum Blades

LINER EQUIPMENT

15

Pump-Down and Liner-Wiper Plugs Anti-Rotational PDC Plug System

PDC Liner-Wiper Plug PDC Pump-Down Plug

The Anti-Rotational PDC Plug System serves the same function as the standard plug system with the added feature of locking clutches in the nosepieces of the liner-wiper plug, pumpdown plug and landing collar. The system includes the pumpdown plug with a non-rotating nosepiece for wiping the drill pipe and setting tool; a liner-wiper plug with non-rotating nosepiece for wiping the liner; and either a type L Landing Collar or HS-SR Landing Collar for the plugs to land in. The locking clutches prevent the rotation of the plugs during drillout which considerably reduces the drillout time. The clutches do not interfere with the latching of the plugs thus preventing cement back-flow.

LR Liner-Wiper Plug Designed to prevent premature release, the LR Liner-Wiper Plug has all of the same features and benefits as the standard PDC LinerWiper Plug. Made up on the tailpipe below the bottom of the setting tool, the LR Liner-Wiper Plug releases when the LR Pump-Down Plug lands and shifts an internal sleeve which then releases a collet, in turn releasing the LR Liner Wiper. The two plugs then move through the liner, keeping the mud separated from the cement while it wipes the liner ID clean.

LR Liner-Wiper Plug with Ball Seat The purpose of the LR Liner-Wiper Plug with Ball Seat is to enable the operator to position a ball seat near the liner top, in the tailpipe directly below the slick joint or packoff assembly. This eliminates the need for a ball-seat-type landing collar such as the PDC HSSR Landing Collar. This is beneficial in areas where the conventional ball-seat landing collar would be positioned at or near horizontal creating a possible seating problem with the ball and the seat. With the ball seat in the LR Liner -Wiper Plug positioned near the liner top, this will increase the possibility of the ball seating properly. Another important benefit of the ball seat being at the liner top is that it reduces the sometimes-harmful pressure surge on the formation when the ball-seat assembly shears out.

LR Liner-Wiper Plug

PR Liner-Wiper Plug

LR Liner-Wiper Plug with Ball Seat

PR Liner-Wiper Plug

The PR (Piston Release) Liner-Wiper Plug has all of the features and benefits of the standard PDC Liner-Wiper Plug but is designed with a piston-release mechanism to prevent premature release. The pistonrelease design releases the PR Liner-Wiper Plug when the Pump-Down Plug is received, giving a positive indication of the plugs’ departure from the setting tool. Well effluents and other harmful contaminants are sealed from entering the release mechanism, resulting in improved performance of the Liner-Wiper Plug System.

16

LINER EQUIPMENT

Tandem Liner-Wiper Plug System* Drill Pipe

When cement mixes with wellbore fluids, cementing failures are common, ranging from poor bonding characteristics to cement that has not hardened at all, even after prolonged curing periods. Experience has also shown that liner length is a key factor in cement contamination. The longer the liner, the higher the probability for wellbore contamination where residual mud cake and well fluids are allowed to mix over extended intervals. The development of the TIW Rotating Liner improved some of the operations associated with liner cementing, but troublesome problems still remained. In 1986, TIW ran the first Tandem LinerWiper Plug System in the North Sea. The purpose of the product was to minimize contamination of the cement during displacement by mechanically containing the cement between two plugs. Today, case histories have shown that the TIW System has reduced contamination from 55 percent to 10 percent — regardless of liner length. The TIW Tandem Liner-Wiper Plug System operates on a twoplug principle (one behind another) to reduce contamination at the interfaces between the cement column and wellbore fluids. The system provides a positive displacement indicator and is particularly beneficial in horizontal or high-angle wells when conventional stage-cementing tools cannot be used. Variations of the system are adaptable for two-stage liner cementing. The Tandem Liner-Wiper Plug System is available in standard sizes from 41⁄2 through 95⁄8 inches. The system’s operating sequence is explained in Figures 1 through 4.

LG Setting Collar

Liner Hanger

Upper Liner-Wiper Plug

Lower Pumpdown Plug

Lower Liner-Wiper Plug

Landing Collar

Lower Pumpdown Plug Upper Liner-Wiper Plug Setshoe

Upper Pump-Down Plug

Fig. 1

Fig. 2


Lower Pump-Down Plug

*U.S. Patent Nos. 4,966,236; 5,018,579 and 5,020,597

LINER EQUIPMENT

17

Figure 1 A lower pumpdown plug, pumped ahead of the cement slurry, isolates the cement from the drilling fluid and wipes the inside of the drill pipe and tool joints. When the plug lands and latches in the lower liner-wiper plug, an applied differential pressure separates the lower plug from the liner plug nipple. During separation, pressure is applied independently to the lower plug and has no effect on the release of the upper plug.

Drill Pipe

Figure 2 When the lower liner-wiper plug seats in the landing collar, an increase of differential pressure exposes the port holes in the liner-wiper plug mandrel so that cement can be pumped around the lower pumpdown plug and into the liner annulus.

Upper Liner-Wiper Plug

Figure 3 To separate the top of the cement column from the displacement fluid, an upper pumpdown plug is pumped behind the cement. When the plug seats and latches in the upper liner-wiper plug, an applied differential pressure releases the upper plug from the liner plug nipple. The two plugs are then free to move through the liner as a single unit, effectively isolating the cement from the displacement fluid.

Upper Pumpdown Plug Upper Liner-Wiper Plug

Figure 4


The upper liner-wiper plug lands and latches in the lower linerwiper plug, forming a positive seal. Once the cement has set, the entire assembly can be drilled out easily.

Lower Pumpdown Plug

Fig. 3

Advantages

Fig. 4

• Upper and lower pumpdown plugs are constructed of drillable material and feature an anti-rotational design. • The lower pumpdown plug/lower liner-wiper plug unit cleans the inside of the setting string and liner of residual mud cake while separating the cement slurry from the drilling fluid, greatly reducing contamination. • The upper pumpdown plug/upper liner-wiper plug unit cleans the inside of the setting string and liner of residual cement and separates the cement from the displacement fluid while providing a positive seal.

18

LINER EQUIPMENT

Setting Tools LN Setting Tool The type LN Setting Tool is used to run and set liners and liner packers when the setting dog feature of the type L tool is not needed. The right-hand release setting nut carries the liner assembly to setting depth. The floating nut and thrust bearing is incorporated in the tool for easy release. With 3,000 to 5,000 pounds of drill pipe weight on the setting nut housing, 12 to 15 right-hand turns will release the setting tool from the liner. A polished extension nipple connected to the setting tool extends through the packoff bushing effecting a positive seal for all cementing operations, or a short tailpipe extension connects the setting tool to the double inverted swab assembly. A strainer on the setting tool handling nipple positioned at the top of the tie-back receptacle acts as a protective barrier and prevents debris from falling between the setting tool and the receptacle.

L Setting Tool This tool will set all compression-set Liner Packers. It combines the features of the type LN Setting Tool with a spring-loaded, rotatable setting-dog section that allows the setting force to be transmitted to the packer. The TIW L Rotating Dogs with Shear Indicator combine the features and benefits of a Type L Setting Dog Section with that of a bearing and a shear indicator. When activated, the spring-loaded setting-dog section permits setting force to be transmitted to the packer while the bearing allows the work string to be rotated at the surface, thus transmitting additional weight to the packer. The shear indicator is actually a “tattletale” device that indicates, when sheared at a predetermined value, that the proper setting weight reached the packer. Both of these features can be beneficial in highangle or horizontal wellbores when attempting to weight-set a liner-top packer.

L Setting Tool

RP-RRP Setting Tool

RP-RRP Setting Tool Use this tool for setting any rotating and/or rotatingreciprocating liner assemblies, as well as with any righthand-set liner hangers. To release the tool from the liner, simply position the setting tool in the release position and rotate to the right. The internal connection of the RP-RRP Setting Tool exceeds the maximum allowable torque of the liner connections.

LN Setting Tool Assembly

LINER EQUIPMENT

19

H1-PL Setting Tool The Hydraulic Release H1-PL Setting Tool is recommended for long-reach, high-angle or horizontal wells. The H1-PL Setting Tool is used with the type C Setting Collar and Liner Packer when it is desirable to release the setting tool from the liner without rotation.

SJ Setting Tool The SJ Setting Tool is designed for use with type C Setting Collars and right-hand-set liner hangers. It is recommended for high-angle or deviated holes and applications in which the liner must be rotated to reach the desired setting depth. The tool has a non-re-engageable feature that prevents re-engagement due to residual torque.

SJ-T Setting Tool The SJ-T Setting Tool is designed to be used with the type C Setting Collar and Liner Hanger settings that require rotation before and after the hanger is set. It is designed with shouldered Acme threads for maximum strength and torque resistance. The tool features a dual rotational arrangement that permits rotation during running and rotation of the liner after the hanger has been set. The SJ-T Setting Tool has a non-re-engageable feature that captures the setting nut and prevents re-engagement of the tool as a result of residual torque. SJ-T Setting Tool

DJ Setting Tool The DJ Setting Tool is designed for applications with type C Setting Collars, right-hand set hangers and for liners that require rotation during running and rotation after the hanger has been set. This product has a non-re-engagable feature that captures the setting nut and prevents re-engagement of the tool as a result of residual torque.

HS Piston Section The HS Piston Section can be run on top of any of TIW’s running tools when hydraulic activation of a liner-top packer is desired. Activation of the piston section is accomplished by utilizing a ball seat below the piston section either in the tail pipe or the liner, or by landing the pump-down/liner-wiper plug into the landing collar. Many operators favor this hydraulic-set feature, especially in high-angle holes where drag causes difficulties in applying weight to the packer, or in holes where small-diameter work strings lack sufficient setting weight.

H1-PL Setting Tool

DJ Setting Tool

SJ Setting Tool Assembly

HS Piston Section

20

LINER EQUIPMENT

Packoff Bushings and Swab Assemblies TIW supplies retrievable or drillable packoff bushings and double inverted swab assemblies for use in cementing operations. These tools are field-proven and manufactured to meet exacting specifications.

B Retrievable Packoff Bushing* The patented type B Retrievable Packoff Bushing eliminates the need for drilling out a bushing after cementing operations are complete, thereby saving a round trip. It provides a firm seal between the setting tool and the liner. The packoff bushing is made up with the liner setting tool, using a polished nipple to extend down through its I.D. A profile to receive and hold the bushing in place is machined into the I.D. of the setting collar or packer. After cementing, the bushing is retrieved with the setting tool. The small cross-sectional area of the polished joint end reduces the piston effect normally associated with large diameter liners.

Drillable Packoff Bushing When a drillable packoff bushing is desired, the TIW bushing is strong enough for high-pressure, high-temperature work. Yet it can be easily removed with a roller bit or mill. The TIW Drillable Packoff Bushing contains a set of internal elastomeric “V” or “W” packing rings which form a tight seal around the polished nipple extension of the setting tool. These seals prevent movement of fluid over the top of the liner and between the setting tool and liner. The bushing holds all cementing, shear-out and plug bumping pressures. And it resists abrasion caused by rotating the setting tool free and moving up or down to check disengagement from the liner.

Double Inverted Swab Assembly The double inverted swab assembly seals the setting tool inside the liner during cementing. When the liner assembly is made up, the swab is installed on a tailpipe or on the bottom of the setting tool. Its design allows the assembly to hold normal pressures associated with circulating, cementing and testing. After cementing is completed, the double inverted swab assembly is retrieved with the setting tool.

Inflation Assembly Inflation Assembly

The TIW Inflation Assembly with hydraulic-activated dogs features opposed swab cups that provide a seal between the setting tool tailpipe and infatable packer. The design allows the assembly to hold normal pressures associated with circulating and testing. The system also includes the hydraulic-activated dogs, plug seats and bypass valve.

Retrievable Packoff Bushing and LG Setting Collar

One-Unit Seal The One-Unit Seal provides an excellent seal between the liner and setting tool. The sub holds pressure from both directions, preventing reverse differential failure during cementing operations, and allows for the setting and/or releasing of hydraulically actuated equipment. To select the proper elastomer, please refer to the Packer Seal System Selection Guide located on page 46.

*U.S. Patent No. 4,281,711

One-Unit Seal Double Inverted Swab Assembly

Drillable Packoff Bushing

LINER EQUIPMENT

21

Cementing Equipment and Accessories Cementing Manifold The TIW Cementing Manifold is a sturdy tool that is simple to operate. It can be provided with a swivel for rotate-and-reciprocate operations and with a ball-dropping sub for setting the Hydro-Hanger when necessary. The tensile rating of the manifold equals or exceeds the tensile rating of the drill pipe. The pumpdown plug is held in the body above the lower manifold valve. Cement is first pumped through the lower valve. Then, when the pumpdown plug is needed, it is released by turning the wheel on the releasing mechanism to retract the plunger rod holding the plug. The upper valve is then opened and the lower valve closed, forcing down the plug. It wipes residual cement from the setting string, then seats in the liner-wiper plug. This plug, in turn, wipes the liner clean until it seats in the landing collar.

Top-Drive Cementing Manifold* The TIW Top-Drive Cementing Manifold is used on rigs that employ a top-drive drilling system or a power swivel as the drill string power source. The unit is particularly beneficial in cementing operations when used in conjunction with rotational and reciprocating liner assemblies. The manifold provides a means of introducing cement, and/or other fluids, into the work string below the top-drive unit without interrupting rotational or vertical movement. A plug-dropping sub beneath the manifold provides fluid diversion until the pumpdown plug is released. This occurs by opening the ball valve in the sub and closing the by-pass valve to divert fluid through the plug-dropping sub. Additional subs may be attached as necessary when employing tandem plugs. A ball-dropping sub can also be used in the work string when setting hydraulic hangers.

Tandem Mill Assembly with Casing Scraper Cementing Manifold with Swivel and Ball-Dropping Sub

Tandem Mill Assembly with Casing Scrapper

The Mill Assembly with Casing Scraper is to be run after the liner cementing job and prior to the running of an SN-AT Liner Packer. The mill portion of this assembly is required to clean out the inside diameter of the tie-back receptacle. This removes cement or other debris that would prevent the seal portion of the packer from properly sealing. The casing scraper, which is spaced out above the mill, is designed not only to scrape debris from the casing’s inside diameter, but it also “dresses off” the top of the tie-back receptacle which is critical in ensuring the proper installation of the SN-AT Packer.

Plug-Dropping Sub Top-Drive Cementing Manifold

*U.S. Patent No. 4,854,383

22

LINER EQUIPMENT

SN-AT Liner Packer* The SN-AT Liner Packer is a close clearance packer designed to provide a high-pressure seal at the top of a cement or uncemented liner. It is run on drill pipe and/or casing, and landed in a receptacle at the top of the liner. In most applications a type LG Receptacle is run with the packer providing for future tie-back. The SN-AT Packer is run after the liner is set, so that maximum annular flow is achieved at the liner top during cementing. This is possible because there is no restriction like that associated with a conventional liner-top packer. The packer and accompanying hold-down slips are set by applying weight. The setting tool is retrieved with the drill pipe. When set, this packer will seal in the liner receptacle and packoff in the casing to isolate the liner top, holding securely against pressures from above or below. The Gold Seal Packoff provides a tight, long-lasting seal against high pressure and high temperatures. The unrestricted bore of the packer allows free passage of full-gauge downhole tools, as well as high volume production.

LG Receptacle

SN-AT Liner Packer

Applications The SN-AT Liner Packer successfully performs a number of important functions in liner top applications: • Provides a high-pressure seal at the liner top • Safely seals micro-annular leaks at the liner top caused by high-pressure gas • Extends a liner to the surface when it is not desirable to cement the tie-back • Allows a PBR-type completion after the liner has been set and cemented by mounting a PBR above it

Retrievable SN-ATR Liner Packer

EJ-IB-TC Liner Hanger

The Retrievable SN-ATR Packer gives the operator all of the characteristics of the SN-AT Liner Packer while delivering the economy and flexibility of retrievability. The Retrievable SN-ATR Packer and any tool run with it can be retrieved with conventional tools using a straight pull. No rotation is required. HighPressure Gas

See page 23 for specifications.

SN-ATR Liner Packer

SN-AT Liner Packer

*U.S. Patent No. 4,537,251; Canadian Patent No. 1,212,623; U.K. Patent No. 2,156,875

LINER EQUIPMENT

23

SN-HS Liner Packer The SN-HS Liner Packer is a hydraulic- or mechanical-set, closetolerance, high-pressure packer that can be run when there is a leak at the top of the liner or if the bond log shows insufficient cement bond. Many operators favor the packer’s hydraulic-set feature in high-angle holes where drag causes difficulties in applying weight to the packer, or in holes where small-diameter work strings lack sufficient setting weight.

HS Piston Section

HS Setting Tool The type HS Setting Tool is designed to set the SN-HS Packer either hydraulically or mechanically. This built-in versatility is a solid benefit to operators.

L Setting Dogs

SN Liner Packer Specifications CASING SIZE

LINER SIZE O.D. In.

Mm.

WEIGHT RANGE Mm.

41⁄2

114.3

071⁄2

177.8

51⁄2

127.0

071⁄2

177.8

51⁄2

127.0

075⁄8

193.7

51⁄2

139.7

075⁄8

193.7

1

7

⁄2

177.8

0

95⁄8

244.5

75⁄8

193.7

095⁄8

244.5

5

193.7

10 ⁄4

273.1

7 ⁄8

L Setting Tool

SN-HS Liner Packer

One-Unit Seal

Ball-Seat Shear Assembly

HS Setting Tool Assembly

O.D. In.

3

MAXIMUM BODY O.D.

Lb./Ft.

Kg./M.

In.

Mm.

23.0-26.0 29.0-32.0 35.0-32.0 23.0-26.0 29.0-32.0 35.0-32.0 20.0-26.4 26.4-33.7 33.7-39.0 20.0-26.4 26.4-33.7 33.7-39.0 36.0-43.5 43.5-53.5 36.0-43.5 43.5-53.5 60.0-65.0

34.2-38.7 43.2-47.6 52.1-47.6 34.2-38.7 43.2-47.6 52.1-47.6 29.8-39.3 39.3-50.2 50.2-58.1 29.8-39.3 39.3-50.2 50.2-58.1 53.6-64.7 64.7-79.6 53.6-64.7 64.7-79.6 89.3-96.8

61⁄16 529⁄32 513⁄16 61⁄16 529⁄32 513⁄16 625⁄32 637⁄64 67⁄16 625⁄32 637⁄64 67⁄16 81⁄2 85⁄16 81⁄2 85⁄16 95⁄16

154.0 150.0 147.6 154.0 150.0 147.6 172.2 167.1 163.5 172.2 167.1 163.5 215.9 211.1 215.9 211.1 236.5

SEALING BORE LENGTH

RECEPTACLE O.D. In.

Mm.

I.D. In.

LG-6 Mm.

In.

Cm.

LG-10 In.

LG-20

Cm. In.

Cm.

5.750 146.05 5.250 133.35 72 182.9 120 304.8 204 609.7

5.750 146.05 5.250 133.35 72 182.9 120 304.8 204 609.7

5.750 146.05 5.250 133.35 72 182.9 120 304.8 204 609.7 6.500 165.10 6.500 165.10 5.750 146.05 72 182.9 120 304.8 204 609.7 6.375 161.93 8.250 8.469 8.250 9.187

209.55 7.375 187.33 72 182.9 120 304.8 240 609.7 215.10 209.55 7.753 196.93 72 182.9 120 304.8 240 609.7 233.36 7.753 196.93 72 182.9 120 304.8 204 609.7

LINER EQUIPMENT

24

LG Liner Extension Assembly The LG Liner Extension Assembly consists of a receptacle, a type LG Seal Nipple and an orifice collar. It has proven to be a superior method of extending the liner to the surface of the well. Using the polished bore receptacle of the LG Setting Collar and type S Liner Packer, this assembly facilitates the entry and subsequent seal of the nipple into the bore. The LG Seal Nipple is run at the bottom of the liner extension. Depending on the application, it employs either a premium, Chevron-type unitized seal assembly or a series of O-rings with lead-faced locator shoulders. Both designs deliver a solid seat and permanent seal. The orifice collar normally included in the LG Liner Extension Assembly is positioned one joint above the seal nipple. This prevents hydraulic blockage as the seal is engaged in the receptacle and allows the liner extension to fill at a predetermined rate as it is run. The orifice collar also serves as a stop for the cement plug. It is constructed of drillable materials. See page 46 for seal selection guide.

High-Pressure Applications For high-pressure tie-back application, a Chevron-type unitized seal assembly is available with metal-to-metal nose and ball seal and matching heavy-duty receptacle. The combination of the heavy-duty receptacle and a dual seal nipple delivers unmatched pressure integrity.

Orifice Collar

LG Seal Nipple LG Receptacle

LG-6 Chevron Seal Nipple with Metal-toMetal Seal

LG Seal Nipple with O-Ring Seals

Enlarged View of Metal-to-Metal Seal

LG Seal Nipple with Unitized Seal Assembly and Orifice Collar Liner Hanger

LINER EQUIPMENT

25

LH Liner Hanger Packer The LH Packer is retrievable, with a sleeve-type packoff element. It is used as the bottom liner hanger and packer, or as a tension packer. The LH Packer is set by weight and is available with or without hold-downs. It has differing applications depending on the use of hold-downs.

Without Hold-Downs Without hold-down slips, the LH Packer is used on the bottom of a full liner to the surface or on a scab liner.

Setting At the desired setting depth, pick up, rotating to disengage the J-slot, and set down. Weight sets the slips and compresses the packoff element, sealing it securely against the casing wall. No setting tool is necessary. The LH Packer is available with either right- or left-hand J-slot.

Retrieving Straight pick-up on the liner releases the LH Packer.

With Hold-Downs The LH Packer with hold-down slips is a retrievable production packer which can be used to suspend pre-packed, drillable or conventional steel screens in flowing or pumping wells.

Setting The LH Packer with hold-down slips is set using the LN Setting Tool. The packer is set by picking up and rotating to the left, disengaging the J-slot. Slack off until about 12,000 pounds of setting string weight is on the packer. This requires travel of about six inches at the packer. Then pick up until about 2,000 pounds is resting on top of the tool. Rotate 12 turns to the right to release the setting tool, pick up and come out of the hole.

Retrieving To retrieve the packer, latch onto tool connection at the top and pull.

LH Liner Hanger Packer

LH Liner Hanger Packer with Hold-Down Slips

LH Liner Hanger Packer Specifications CASING SIZE O.D. In.

Mm.

4 41⁄2 41⁄2 5 5 51⁄2 51⁄2 51⁄2 53⁄4 53⁄4 6 65⁄8 65⁄8 7 7 7 65⁄8 7 7 7 75⁄8 75⁄8 75⁄8 75⁄8 75⁄8 85⁄8 85⁄8 85⁄8 85⁄8 85⁄8 95⁄8 95⁄8 95⁄8 95⁄8

101.6 114.3 114.3 127.0 127.0 139.7 139.7 139.7 146.1 146.1 152.4 168.3 168.3 177.8 177.8 177.8 168.3 177.8 177.8 177.8 193.7 193.7 193.7 193.7 193.7 219.1 219.1 219.1 219.1 219.1 244.5 244.5 244.5 244.5

WEIGHT RANGE Lb./Ft. Kg./M. 09.5-11.6 09.5-13.5 09.5-13.5 11.5-13.0 13.0-18.0 14.0-20.0 14.0-17.0 17.0-20.0 17.0-22.5 17.0-22.5 15.0-20.0 19.0-24.0 26.0-32.0 17.0-23.0 26.0-32.0 20.0-26.0 19.0-24.0 26.0-32.0 20.0-26.0 20.0-26.0 20.0-26.0 26.4-33.7 33.7-39.0 20.0-26.4 26.4-33.7 24.0-32.0 32.0-40.0 40.0-49.0 24.0-32.0 32.0-40.0 29.3-40.0 43.5-53.5 32.0-40.0 40.0-47.0

14.1-17.3 14.1-20.1 14.1-20.1 17.1-19.4 19.4-26.8 20.8-29.8 20.8-25.3 25.3-29.8 25.3-33.5 25.3-33.5 22.3-29.8 28.3-35.7 38.7-47.6 25.3-34.2 38.7-47.6 29.8-38.7 28.3-35.7 38.7-47.6 29.8-38.7 29.8-38.7 29.8-38.7 39.3-50.2 50.2-58.1 29.8-39.3 39.3-50.2 35.7-47.6 47.6-59.5 59.5-72.9 35.7-47.6 47.6-59.5 43.6-59.5 64.7-79.6 47.6-59.5 59.5-69.9

LINER SIZE O.D. In. Mm. 23⁄8 23⁄8 27⁄8 31⁄2 31⁄2 31⁄2 4 4 31⁄2 4 41⁄2 41⁄2 41⁄2 51⁄2 41⁄2 41⁄2 5* 5 5 51⁄2* 5 5 5 51⁄2 51⁄2 51⁄2 51⁄2 51⁄2 65⁄8 65⁄8 7 7 75⁄8 75⁄8

60.3 60.3 73.0 88.9 88.9 88.9 101.6 101.6 88.9 101.6 114.3 114.3 114.3 139.7 114.3 114.3 127.0* 127.0 127.0 139.7* 127.0 127.0 127.0 139.7 139.7 139.7 139.7 139.7 168.3 168.3 177.8 177.8 193.7 193.7

MAXIMUM BODY O.D. In. Mm. 35⁄32 321⁄32 321⁄32 415⁄64 41⁄16 49⁄16 411⁄16 49⁄16 413⁄16 413⁄16 51⁄4 55⁄8 53⁄8 61⁄8 53⁄4 57⁄8 55⁄8 53⁄4 57⁄8 515⁄16 65⁄8 67⁄16 61⁄4 65⁄8 67⁄16 71⁄2 75⁄16 71⁄8 71⁄2 75⁄16 829⁄64 83⁄16 829⁄64 85⁄16

Popular sizes shown. Other sizes available from your TIW representative. *I.D. restricted for some weights.

80.2 92.9 92.9 107.6 103.2 115.9 119.1 115.9 122.2 122.2 133.4 142.9 136.5 155.6 146.1 149.2 142.9 146.1 149.2 150.8 168.3 163.5 158.8 168.3 163.5 190.5 185.7 181.0 190.5 185.7 214.7 208.0 214.7 211.1

LINER EQUIPMENT

26

HP Liner Hanger Packer The TIW HP Liner Hanger Packer is a versatile tool. It functions as a packer, a liner hanger and a polished-bore, tie-back receptacle. The polished receptacle is available in various lengths. For all its utility, it is still compact and rugged and is available with or without external hold-down slips. The HP Packer features a machined upper sleeve and standard packoff elements for situations not requiring Gold Seal Packoff elements. A TIW type L Setting Tool is used to lower the liner and the HP Liner Hanger Packer into the well. When set, the packoff elements are held in the expanded position by a ratchet ring in the sleeve, isolating the liner top from fluid encroachment. With cement placed and the HP Packer set, excess cement can be reversed out without exposing pressure-sensitive formations to excessive pressures. HP Liner Hanger Packer Specifications CASING SIZE O.D. In.

LINER SIZE O.D.

WEIGHT RANGE

MAXIMUM BODY O.D.

Mm.

Lb./Ft.

Kg./M.

In.

Mm.

In.

Mm.

51⁄2

139.7

14.0-20.0 14.0-17.0 17.0-20.0

20.8-29.8 20.8-25.3 25.3-29.8

31⁄2 4 4

88.9 101.16 101.16

4.563 4.688 4.563

115.9 119.1 115.9

65⁄8

168.3

19.0-24.0

28.3-35.7

41⁄2

114.30

5.625

142.9

7

177.8

17.0-23.0 26.0-32.0 20.0-26.0

25.3-34.2 38.7-47.6 29.8-38.7

51⁄2 41⁄2 41⁄2

139.7 114.3-127.0 114.3-127.0

6.125 5.750 5.875

155.6 146.1 149.2

75⁄8

193.7

20.0-26.4 26.0-33.7 33.7-39.0

29.8-39.3 38.7-50.2 50.2-58.1

5-51⁄2 5-51⁄2 5

127.0-139.7 127.0-139.7 127.0

6.625 6.438 6.250

168.3 163.5 158.8

85⁄8

219.1

24.0-32.0 32.0-40.0 40.0-49.0

35.7-47.6 47.6-59.5 59.5-72.9

51⁄2

139.7

7.500 7.312 7.125

190.5 185.7 181.0

95⁄8

244.5

43.5-53.5 29.3-40.0 36.0-47.0

64.7-79.6 43.6-59.5 53.6-69.9

7

177.8

8.453 8.250 8.375

209.6 214.7 212.7

HP Liner Hanger Packer

HHP Hydro-Hanger Packer

COILED-TUBING-DEPLOYED LINER SYSTEMS

27

Coiled-Tubing-Deployed Liner Products For more than 80 years, TIW has made the most reliable liner products in the industry. As coiled-tubing drilling has become a widely used technology, both major and independent operators have turned to it as a cost-effective alternative to traditional rotary drilling. Now TIW has taken its expertise in larger-bore liner technology and applied it to coiled-tubing operations. We have developed a wide array of liner products for both cemented and non-cemented completions, giving our customers the ability to meet the conditions found on any small-bore project with total confidence.

CT Hydraulic Packer/Hanger This tool incorporates a packer and a liner into one unit. Run on coiled tubing and set with the Bonsai Setting Tool, the CT Packer/Hanger is set by applying pressure through the coiled tubing. Additional pressure is applied to release the Bonsai Setting Tool. After cementing, the tool is repositioned to set the packer. Once the packer is set, the tool is removed from the wellbore.

CT Hanger with Tie-Back Receptacle The CT Hanger with Tie-Back Receptacle is a coiled-tubing-deployed combination of hanger, tie-back receptacle and setting collar. It requires the CT Hydraulic Tool, run with the Bonsai Setting Tool, to set and lock the liner hanger in position.

Bonsai Setting Tool This setting tool is used in coiled-tubing deployment of wellbore liner assemblies. The tool is run at the transition point between the coiled-tubing workstring and the liner. It is then used to convey the liner to setting depth and then release from the liner with the application of a specific internal pressure. The connecting latch of the tool is furnished with high-degree flank angles, ensuring ease of release under the highest wellbore inclinations and the most severe conditions.

Bonsai Setting Tool

CT Hanger with Tie-Back Receptacle

CT Hydraulic Hanger/Packer

PACKER-BORE RECEPTACLE SYSTEM

28

PBR System In 1968, TIW introduced the Packer-Bore Receptacle (PBR) — the petroleum industry’s first successful method for creating a packerless, free-end, tubing-to-casing seal that maintained a total seal integrity. Since then, thousands of TIW PBRs have been used in wells around the world for meeting the special requirements of deep well completions. The Packer-Bore Receptacle provides the maximum internal opening through the production tubing and sealing system. It allows tubing to lengthen and contract in response to pressure and/or temperature without affecting the integrity of the tubingto-casing seal.

Packer-Bore Receptacle Assembly The PBR is actually an assembly composed of two parts: the PackerBore Receptacle and the Packer-Bore Receptacle Seal Assembly. The first, the Packer-Bore Receptacle, is usually run as an integral part of the liner or casing string. It is a specially honed and coated receptacle that allows the tubing string to contract and/or expand in response to pressure and temperature, while maintaining the highest degree of sealing capability. The honed inside surface of the TIW PBR is Teflon-coated to prevent cement or other material from adhering. This coating minimizes corrosion caused by metal-to-metal contact and well effluents. The second part of the PBR is the Packer-Bore Receptacle Unitized Seal Assembly which connects to the end of the tubing string and mates into the PBR. To prevent leakage, the unitized seal assembly mandrel has no threaded connections or O-rings between seal units. Mounted on the outside of this assembly is a series of annular Chevron rings supported by back-up rings made of Teflon or other materials. The Chevron rings are available in several different materials. The sets of Chevron rings form an O.D. somewhat greater than the I.D. of the PBR and are resilient enough to be compressed into the polished, Teflon-coated bore. The number of sealing rings per set, the number of sets used and the materials used may vary with well conditions or applications.

PBR System Components To offer unmatched seal integrity, safety and versatility, TIW has engineered the following PBR system components: Packer-Bore Receptacle (PBR) Retrievable Landing Nipple (RLN) Retrievable PBR with Positive Latch (patent pending) Dual-Flow PBR Assembly PBR with RLN Profile

PBR Seal Nipple

® Teflon is a registered trademark of E.I. DuPont de Nemours & Co., Inc. ™ RLN is a trademark of TIW.

PACKER-BORE RECEPTACLE SYSTEM Production Tubing

Production Tubing Liner Tie-Back Locator Sub Protection Casing

Locator Sub

LG Setting Collar

Unitized PBR Seal Assembly PBR

Liner Extension SN-AT Liner Packer

HydroHanger Liner LG Seal Assembly (Metal-toMetal Seals)

LG Setting Collar

LG Setting Collar (Metal-toMetal Seals) EJP Liner Hanger

PBR

Unitized PBR Seal Assembly

Liner Hanger Protection Casing

Liner

Liner

29

Applications of the PBR The PBR is typically run on top of the production liner or as a transition segment of a tapered casing or liner string. Due to its unmatched seal-to-bore tolerance, the PBR system provides optimum performance in wells with high production rates. It is an extremely safe completion system in high-pressure, high-temperature wells. Because of its full-bore, thru-tubing workover is possible, as well as high-pressure, high-volume remedial and stimulation work. The full-bore also allows the largest possible perforating guns and other downhole tools to pass freely through it. A major advantage of the PBR system is that the free end of the tubing can move up or down due to changes in temperature or pressure. And because of the reliability of the seal, that movement will not cause any leakage. Packer-Bore Receptacle Specifications RECEPTACLE O.D.

RECEPTACLE I.D.

MAXIMUM I.D. THROUGH SEAL ASSEMBLY

In.

Mm.

In.

Mm.

In.

Mm.

133⁄4 131⁄2 133⁄4 141⁄4 141⁄2 141⁄2 15 151⁄4 151⁄2 153⁄4 16 161⁄4 161⁄2 17 171⁄4 171⁄2 173⁄4 181⁄4 181⁄4 10 10 105⁄8

95.25 88.90 95.25 107.95 114.30 127.00 127.00 133.35 139.70 146.05 152.40 158.75 165.10 177.80 184.15 190.50 196.85 209.55 209.55 254.00 254.00 269.88

2.500 2.688 3.000 3.250 3.250 3.500 3.750 4.000 4.250 4.400 4.750 5.000 5.250 5.750 5.750 6.000 6.250 7.035 7.375 7.750 7.875 8.438

63.50 68.28 76.20 82.55 82.55 88.90 95.25 101.60 107.95 111.76 120.65 127.00 133.35 146.05 146.05 152.40 158.75 178.69 187.33 196.85 200.03 214.33

1.875 1.938 2.375 2.375 2.375 2.500 2.500 2.750 2.875 3.000 3.250 3.750 4.000 3.964 4.750 4.276 4.670 5.938 6.188 6.188 6.000 6.560

47.63 49.21 60.33 60.33 60.33 63.50 63.50 69.85 73.03 76.20 82.55 95.25 101.60 100.69 120.65 108.61 118.62 150.83 157.16 157.16 152.40 166.62

30


Dual-Flow PBR Assembly

Production Tubing

The Dual-Flow PBR Assembly offers all standard dual capabilities without restriction. In this assembly, the lower zone can be produced through a PBR or packer installed just above the lower production area. The upper zone is produced through the Dual-Flow Assembly incorporating PBR seals. This upper receptacle is usually run in conjunction with a liner hanger or a liner tie-back. The separate seal assemblies on each string allow them to move independently in response to pressure and temperature. The TIW Dual-Flow PBR Assembly can be used in a variety of applications, both dual and single completions including injection, stimulation, kill string and continuous treatment.

Locator Sub

Unitized PBR Seal Assembly Dual-Flow PBR Assembly

LG Setting Collar

Unitized PBR Seal Assembly PBR Hydro-Hanger

Liner

LG Setting Collar Locator Sub

Unitized PBR Seal Assembly PBR RLN

Liner

Dual-Flow PBR Assembly


31

RLN Retrievable Landing Nipple*

Locator Sub

The TIW Retrievable Landing Nipple provides a retrievable method of suspending conventional landing nipples and tailpipe from the bottom of the PBR. The RLN-M-2 features multiple lugs which latch into a profile in the lower section of the PBR. Seals constructed on any of the modern sealing compounds provide a non-moving, high-pressure seal. The RLN-M-2 is mechanically set. When running, it is positioned opposite the corresponding profile in the PBR by locating on a “no-go.” Rotation frees the RLN-M-2 setting tool, allowing weight to be applied to the setting sleeve, shearing the retaining pin and latching the lugs into the PBR. The RLN-M-2 setting tool indicates when the Retrievable Landing Nipple has fully engaged with the RLN profile. For remedial work the RLN is a simple way to temporarily seal off the well without the use of fluids. A plug is run and set via wireline after which the tubing is retrieved. Upon completion of remedial work, the tubing seal assembly is resealed into the PBR. The plug is then retrieved on wireline and the well put back on production.

LG Receptacle


PBR

RLN Wireline Plug

Retrievable Landing Nipple Specifications PBR I.D.

Liner Hanger

RLN O.D.

RLN I.D.*

In.

Mm.

In.

Mm.

In.

Mm.

3.250 3.750 4.000 4.250 4.750 6.250

82.55 95.25 101.60 107.95 120.65 158.75

3.220 3.719 3.969 4.220 4.720 6.219

81.79 94.46 100.81 107.19 119.89 157.96

2.188 2.250 2.500 2.500 2.750 3.656

55.56 57.15 63.50 63.50 69.85 92.87

*Other RLN I.D. available upon request.

Liner

RLN-M-2

*U.S. Patent Nos. 4,248,300 and 4,993,493 Canadian Patent No. 1,249,966 U.K. Patent No. 2,175,030B


32

Retrievable Packer-Bore Receptacle

Production Tubing

TIW developed the Retrievable Packer-Bore Receptacle in response to the problems caused by the use of small-diameter tubing (27⁄8 inches O.D. and smaller) in completing deep, high-pressure wells. It is a known fact that small-diameter tubing is more susceptible than larger-diameter tubing to the stress caused by downhole pressure acting against the tubing’s inner wall, coupled with the effect of bending acting against its outerwall. This stress produces buckling; and if great enough, results in corkscrewing and/or permanent tubing deformation. A TIW Packer-Bore Receptacle is the ultimate solution to the stress problem because it will allow the tubing to elongate and contract while maintaining an integral seal. But to seal small-diameter tubing into a polished bore, with an I.D. that is larger than the O.D. of the tubing, will also cause stress to the tubing. The tubing needs support all around its O.D. along the portion that is actually in the polished bore. The solution lies in reducing the seal bore so the tubing is supported by the receptacle, with a minimum gap between the tubing and the polished bore. To reduce the polished bore I.D., TIW developed the Retrievable Packer-Bore Receptacle Assembly. It consists of a Retrievable Landing Nipple (RLN) with a small-diameter receptacle made up on its top. The RLN/Retrievable PBR assembly connects to, and is run on, the work string. The RLN, which is on the bottom of the assembly, latches into the full-size PBR which is already in place. This attaches the Retrievable PBR to the larger PBR. Now the small-diameter tubing can accommodate the pressure/temperature-induced forces in the well without damaging stress. When using a Retrievable PBR, the larger PBR (in the casing or liner) only needs to be of minimal length to receive the Retrievable Landing Nipple. Retrievable PBR/RLN Specifications PBR I.D.

RLN O.D.

RLN I.D.

Locator Sub Retrievable PBR

LG Receptacle Protection Casing


PBR

RLN

Landing Nipple Liner Hanger

RETRIEVABLE PBR I.D.

RETRIEVABLE PBR O.D.

In.

Mm.

In.

Mm.

In.

Mm.

In.

Mm.

In.

Mm.

3.750 4.000 4.250 4.750

95.25 101.60 107.95 120.65

3.720 3.970 4.220 4.720

94.49 100.84 107.19 119.89

2.250 2.500 2.500 2.750

57.15 63.50 63.50 69.85

3.005 3.255 3.255 3.005

76.33 82.68 82.68 76.33

3.720 3.970 4.220 4.720

94.49 100.84 107.19 119.89

*Other RLN I.D. available upon request.

Liner


33

Packer-Bore Receptacle with Positive Latch* The latest development in the TIW PBR Completion System is a retrievable PBR with a positive latch. It is available with either the full- or reduced-bore (Retrievable) PBRs. The TIW Positive Latch allows the operator to latch the PBR into an existing liner. The PBR with positive latch can be run in one trip by using a complete assembly that consists of tubing, seals, landing nipples and PBR. The assembly offers several benefits: • Economical — Its one-trip feature saves rig time. • Options — It allows free-end or latched-tubing connections. • Retrievable — It can be retrieved with the production tubing and does not require special tools. • Protection — Due to the assembly’s design, the production seals are protected from damage during run-in, because they are enclosed in the Retrievable PBR. • Flexibility — It does not require a special PBR receptacle, but may be used with an LG Setting Collar with RPOB profile.

Positive Latch with Seal Assembly

PBR Receptacle with Positive Latch

*U.S. Patent No. 4,646,842 Canadian Patent No. 1,225,929 U.K. Patent No. 2,157,743

Electronic Engineering Handbook eEHB Section 6

Printed: 6/11/2006

EDC, Tomball, TX

API Version

Printed: 6/11/2006

EDC, Tomball, TX

1

Double click the BJ Icon (eEHB Version 1.60) EDC, Tomball, TX

EDC, Tomball, TX

2

EDC, Tomball, TX

Capacity

EDC, Tomball, TX

3

CAPACITY

VOLUME of tubulars or open hole.

EDC, Tomball, TX

CAPACITY

2-7/8” 6.5 #/ft

2-7/8” 10.7 #/ft EDC, Tomball, TX

4

LnFt/Gal Gal/LnFt Weight LnFt/CuFt Inside Outside Bbl/lf CuFt/LnFt lb/ft LnFt/Bbl Diameter diameter in inches feet ofoftubing How many gallons will CuFt barrels of tubing will be filled by one will foot be filled ofone by one hold. gallon fluid will foot of fittubing in one foot one CuFt of fluid. of fluid. tubing hold bytubing. one bbl of fluid.

EDC, Tomball, TX

EDC, Tomball, TX

5

EDC, Tomball, TX

EDC, Tomball, TX

6

EDC, Tomball, TX

Significant Digits and Decimal Places Depends on the parameter, the unit of measure and the situation…… use ENGINEERING JUDGEMENT. ³ Depths, Heights and Slurry Volumes Ë 2,463 ft, 210.2 bbls, 1,349 gals, 548.7 ft³

³ Hydrostatic Pressures Ë 1,566 psi

³ Slurry Densities, Slurry Yield and Mix Water Ë 15.6 ppg, 1.252 ft³/sk, 5.18 gal/sk or 51.3%

Do not round results of intermediate calculations.

EDC, Tomball, TX

7

1. How many linear feet will be occupied by 1,500 gallons of KCl water in 4-1/2”, 11.6 #/ft casing ?

EDC, Tomball, TX

2. How many cubic feet (ft3) of cement do I need to fill 1,962’ of 4”, 14 #/ft internal upset drill pipe ?

EDC, Tomball, TX

8

3. How many barrels (bbls) are required to displace to the top perforation at a depth of 8,457’ in 7”, 26 #/ft casing ?

EDC, Tomball, TX

4. How many gallons would it take to displace to a depth of 6,923’ in 2-3/8”, 4.7 #/ft tubing ?

EDC, Tomball, TX

9

5. How many feet of fill will result from 5,000 ft3 of cement in a 60” open hole ?

EDC, Tomball, TX

6. 13-3/8”, 68 #/ft casing Calculate: 1. Displacement volume in barrels. 2. Shoe joint capacity in cubic feet.

Float Collar @ 992’ Guide Shoe @ 1,032’ Shoe joint EDC, Tomball, TX

10

7. Calculate TD of this 65” open hole. 765 bbls of 2% KCl

2,500 ft3 of 14.8 ppg cement

1,150 gallons of 15% HCl

1,200 ft3 fresh water EDC, Tomball, TX

Treatment: 1,000 gallons 15% HCl 5”, 18 #/ft casing to 10,100’

8.

2-3/8”, 4.70 #/ft, EUE, tubing to 9,050’

Calculate displacement to have acid on bottom perfs. Packer @ 9,050’ 10,000’ 10,050’ EDC, Tomball, TX

11

EDC, Tomball, TX

Tubing or Casing Inside

ANNULUS

Casing or Open Hole Outside

EDC, Tomball, TX

12

EDC, Tomball, TX

OD of outside lbs per ftIDofof outside casing casing outside casing Click on OD of inside pipe

Other factors same as before

EDC, Tomball, TX

13

Diameter of Hole Click on OD of inside pipe

Other factors same as before

EDC, Tomball, TX

1. How many feet of fill would be provided by 1,500 gallons in the annulus between 5-3/4” casing and 8-1/8”, 35.5 #/ft casing ?

EDC, Tomball, TX

14

2. You have a retrievable treating packer on 2-7/8”, 6.5 #/ft tubing in casing that is 9-5/8”, 43.5 #/ft, C-75. Packer is set at 12,238’ and the bypass is open; you are to circulate 35 bbls of 9.8 ppg brine and spot it in the annulus above the packer. What will be the depth of the top of brine after it is spotted ?

EDC, Tomball, TX

3. How many feet would 1,000 gallons of 10 ppg mud occupy in the annulus of 13-3/8” casing in a 17” hole ?

4. How many ft3 of cement would it take to cover 1,250’ of annulus with 7” casing in 10-3/4” open hole ?

5. Given 2-7/8” tubing in 6-5/8”, 28#/ft casing. Packer at 8,500’. How many bbls of 2% KCl are on the backside if the hole is full ?

EDC, Tomball, TX

15

6. Given 1,000 sacks of cement @ 1.32 ft3/sk in the annulus of 5-1/2” casing in 7-7/8” open hole. How many feet will be occupied ?

7. How many gallons of spacer fluid will it take to cover 1,125’ with 7” casing in 13-1/2” open hole ?

EDC, Tomball, TX

5-1/2”, 15.5# to 9,300’

8.

2-7/8”, 7.9# tbg to 9,200’ 1. Calculate how much fluid it will take to load the backside. 2. Calculate displacement to top perforation. Pkr @ 9,200’ 9,255’ 9,280’ EDC, Tomball, TX

16

3-1/2”, 15.8# tbg 10-3/4”, 51# csg to 4,650’ 6-5/8”, 24# liner hung @ 4,500’ 1. Calculate annular volume. 2. Calculate displacement to packer.

Pkr @ 7,059’ 7,090’ 7,448’ EDC, Tomball, TX

Working in the annular space between more than one string of tubing in pipe or open hole.

EDC, Tomball, TX

17

Working with pipe in pipe.

EDC, Tomball, TX

Working with pipe in open hole.

EDC, Tomball, TX

18

Select pipe in pipe

Select the inside pipe size 2-7/8” Select the number of tubing strings

EDC, Tomball, TX

1. Working with 2 strings of 2-7/8” tubing inside of 9-5/8” 36#/ft casing. How many barrels of fluid would it take to fill 1,000 feet of annular space?

EDC, Tomball, TX

19

2. Given three strings of 2-3/8” tubing inside a 6-1/2” hole, how many ft3 of water will it take to fill 1,500 feet of annular space?

EDC, Tomball, TX

3. Given four strings of 2-7/8” tubing inside a 9”, 38#/ft casing, how many feet would be occupied by 250 barrels of 2% KCl water ?

EDC, Tomball, TX

20

8-1/2” open hole

4.

2-3/8” tubing 1. How many feet are occupied by 50 bbls of fluid ? 2. How many gallons will it take to fill 750’ of annulus ?

EDC, Tomball, TX

Exercises 5. How many feet of annular space would be filled by 150 barrels of fluid in the annular space between 3 strings of 3-1/2” tubing and 13-3/8” 68 #/ft casing?

6. How many gallons of water would it take to fill 500’ of annular space between 2 strings of 1-¼” tubing inside of 4-1/2” 11.6 #/ft casing?

EDC, Tomball, TX

21

EDC, Tomball, TX

What if you have two different size tubing strings inside of casing or open hole, and you want to find a bbl/lf factor?

(D2 – d2 – d2) X 0.0009714 D = inside diameter of outside pipe or hole size d = outside diameter of inside pipe 1. Given one string of 2-3/8” tubing and a string of 1-1/4” coil tubing inside of 7” 24 lb casing. What is the bbl/ft factor for the annular space?

EDC, Tomball, TX

22

Metal Displacement

How much fluid will the pipe displace from the well, when run in a hole full of fluid. Note: must be open ended pipe

EDC, Tomball, TX

Metal Displacement Volume of pipe (ft3) = 0.002044 x Wt of Pipe (lbs/ft w/ couplings) x Depth (ft) Volume of pipe (bbls) = 0.000364 x Wt of Pipe (lbs/ft w/couplings) x Depth (ft)

EDC, Tomball, TX

23

What is the fluid volume displaced by 2,000ft of 9 5/8” 53.5 lb/ft casing run with an autofill float valve?

EDC, Tomball, TX

Dimensions and Strengths

Collapse, Internal Yield and Joint Strength are minimum values with no safety factor.

Used in the field these values should be reduced by a minimum of 20%.

EDC, Tomball, TX

24

Dimensions and Strengths Terminology for Pipe Connections Box - internal (female) threaded end Pin - external (male) threaded end Flush Joint - connection with male and female threads cut directly into the pipe. NUE - non-upset end EUE - external upset ends - forging of ends on pipe to provide additional thickness for strengthening connections T&C - threaded and coupled - male threads are cut into the pipe and a coupling provides female threads

EDC, Tomball, TX

Dimensions and Strengths Terminology for Pipe Connections

EDC, Tomball, TX

25

Click on Dimensions and Strengths Click on the tubular you are working with.

EDC, Tomball, TX

Working with Tubing

Outside diameter Weight of pipe lb/ft Inside Diameter Grade of pipe Drift of pipe

EDC, Tomball, TX

26

Working with Tubing

Joint strength Collapse Internal yield (Burst) Book value multiplied by 80% = recommended value in the field for collapse, burst, and joint strength.

EDC, Tomball, TX

1. What is the ID of 8-5/8”, H-40 32#/ft casing ?

2. What is the strongest grade of 2-3/8” tubing ?

3. What is the recommended burst for 4-1/2”, 16.6#/ft, Type E drill pipe ?

4. What is the recommended tensile load of 2-7/8”, 6.5 #/ft, EUE, N-80 tubing ?

EDC, Tomball, TX

27

5. What is the ID of 5-1/2”, 23#/ft, N-80 casing ?

6. What is the internal yield value in the tables for 9-5/8”,29.30 #/ft, F-25 casing ?

7. What is the recommended internal yield value for 7”,38 #/ft N-80 casing ?

8. What is the recommended collapse for 20”, 106.5 #/ft, J-55 casing ? EDC, Tomball, TX

Cement

EDC, Tomball, TX

28

Cement or Additive Bulk Volume #/cuft Absolute Volume cuft/lb gal/lb Specific Gravity

EDC, Tomball, TX

Six Important Factors: CEMENT

Density - ppg Yield - cuft / sk Mix Water - gals / sk Mix Fluid - gals / sk Cuft / Yield = Sacks Sacks X Yield = Cuft EDC, Tomball, TX

29

YIELD (ft3/sk) MIXING WATER (gps) DENSITY (ppg) API Type of Recommended Cement Density

EDC, Tomball, TX

1. What would be the water requirement and yield for Class C mixed at 14.8 ppg ?

EDC, Tomball, TX

30

2. What is the density and water requirement for Class G with a yield of 1.14 ft3/sk ?

EDC, Tomball, TX

3. What would be the water requirement for Class H mixed at 16.8 ppg ?

EDC, Tomball, TX

31

Brines and Hydrocarbons

EDC, Tomball, TX


EDC, Tomball, TX

32

Conversion Factors

EDC, Tomball, TX

Canadian Metric Version

Printed: 6/11/2006

EDC, Tomball, TX

33

Double click the BJ Icon (eEHB Version 1.60) EDC, Tomball, TX

EDC, Tomball, TX

34

EDC, Tomball, TX

Capacity

EDC, Tomball, TX

35

CAPACITY

VOLUME of tubulars or open hole.

EDC, Tomball, TX

CAPACITY

73.025 mm 9.67 kg/m

73.025 mm 15.92 kg/m

EDC, Tomball, TX

36

EDC, Tomball, TX

EDC, Tomball, TX

37

EDC, Tomball, TX

EDC, Tomball, TX

38

EDC, Tomball, TX

Significant Digits and Decimal Places Depends on the parameter, the unit of measure and the situation…… use ENGINEERING JUDGEMENT. ³ Depths, Heights and Slurry Volumes Ë 2,463 ft, 210.2 bbls, 1,349 gals, 548.7 ft³ Ë 1,223.3 m, 212.24 m3, 122.5 L

³ Hydrostatic Pressures Ë 1,566 psi Ë 24,500 kPa, 24.22 MPa

³ Slurry Densities, Slurry Yield and Mix Water Ë 15.6 ppg, 1.252 ft³/sk, 5.18 gal/sk or 51.3% Ë 1,200.1 kg/m3, 0.7493 m3/t, or 45.2%

Do not round results of intermediate calculations. EDC, Tomball, TX

39

1. How many linear meters will be occupied by 5.5 m3 of 2% KCl water in 114.3 mm, 17.2627 kg/m casing ?

EDC, Tomball, TX

2. How many cubic meters (m3) of cement do I need to fill 600 meters of 101.6 mm, 20.8343 kg/m internal upset drill pipe ?

EDC, Tomball, TX

40

3. How many m3 are required to displace to the top perforation at a depth of 2,575 m in 177.8 mm, 38.69226 kg/m casing ?

EDC, Tomball, TX

4. How many gallons would it take to displace to a depth of 6,923’ in 2-3/8”, 4.7 #/ft tubing ?

EDC, Tomball, TX

41

5. How many meters of fill will result from 150 m3 of cement in a 1.524 m open hole ?

EDC, Tomball, TX

6. 339.725 mm, 101.195 kg/m casing Calculate: 1. Displacement volume in m3. 2. Shoe joint capacity in m3.

Float Collar @ 300 m Guide Shoe @ 312 m Shoe joint EDC, Tomball, TX

42

7. Calculate TD of this 1.651 meter open hole. 121.6 m3 of 2% KCl 70.8 m3 of 1.773 s.g. cement 4,350 liters of 15% HCl

34 m3 fresh water

EDC, Tomball, TX

8. Calculate displacement to have the leading edge of 3.75 m3 15% HCl Acid reach the bottom perforation. 60.325 mm, 6.994 kg/m, EUE, tubing to 2,750 m

Packer @ 2,750 m 127.0 mm, 26.787 kg/m casing to 3,075 m 3,045 m 3,060 m EDC, Tomball, TX

43

EDC, Tomball, TX

Tubing or Casing Inside

ANNULUS

Casing or Open Hole Outside

EDC, Tomball, TX

44

EDC, Tomball, TX

OD of outside casing Click on OD of inside pipe

ID of outside casing lbs per ft of outside casing

Other factors same as before EDC, Tomball, TX

45

Diameter of Hole Click on OD of inside pipe Other factors same as before

EDC, Tomball, TX

1. How many meters of fill would be provided by 5.5 m3 in the annulus between 146.05 mm casing and 206.375 mm, 52.8298 kg/m casing ?

EDC, Tomball, TX

46

2. You have a retrievable treating packer on 73.025 mm, 9.673 kg/m tubing in casing that is 244.475 mm, 64.735 kg/m, C-75. Packer is set at 3,730 m and the bypass is open; you are to circulate 5.56 m3 of 1.175 s.g. brine and spot it in the annulus above the packer. What will be the depth of the top of brine after it is spotted?

EDC, Tomball, TX

3. How many meters would 3.75 m3 of 1,200 kg/m3 mud occupy in the annulus of 339.725 mm casing in a 431.8 mm hole?

4. How many m3 of cement would it take to cover 381 m of Annulus with 177.8 mm casing in 273.05 mm open hole?

5. Given 73.025 mm tubing in 168.275 mm, 41.669 kg/m casing. Packer at 2,590 m. How many m3 of 2% KCl are on the backside if the hole is full?

EDC, Tomball, TX

47

6. Given 50 tonnes of cement @ 0.772 m3/t in the annulus of 139.7 mm casing in 200.025 mm open hole. How many meters will be occupied ?

7. How many cubic meters of spacer fluid will it take to cover 343 m with 177.8 mm casing in 342.9 mm open hole ?

EDC, Tomball, TX

8a. Calculate how much fluid it will take to load the backside. 8b. Calculate displacement to the top perforation.

73.025 mm, 11.7565 kg/m tbg to 2,805 m

Pkr @ 2,805 m 139.7 mm, 23.0665 kg/m to 2,835 m 2,821 m 2,829 m EDC, Tomball, TX

48

9a. Calculate the annular volume. 9b. Calculate displacement to the packer. 168.275 mm, 35.716 kg/m liner hung @ 1,371.6 m 273.05 mm, 75.896 kg/m csg to 1,417.3 m

88.9 mm, 23.513 kg/m tubing Packer @ 2,151.5 m 2,161 m 2,270 m EDC, Tomball, TX

Working in the annular space between more than one string of tubing in pipe or open hole.

EDC, Tomball, TX

49

Working with pipe in pipe.

EDC, Tomball, TX

Working with pipe in open hole.

EDC, Tomball, TX

50

Select pipe in pipe

Select the inside pipe size 73.025 mm Select the number of tubing strings

EDC, Tomball, TX

1. Working with 2 strings of 73.025 mm tubing inside of 244.475 mm, 53.5739 kg/m casing. How many barrels of fluid would it take to fill 300 meters of annular space?

EDC, Tomball, TX

51

2. Given three strings of 60.325 mm tubing inside a 165.1 mm hole, how many cubic meters of water will it take to fill 457 meters of annular space?

EDC, Tomball, TX

3. Given four strings of 73.025 mm tubing inside a 228.6 mm, 56.55 kg/m casing, how many meters would be occupied by 40 cubic meters of 2% KCl water?

EDC, Tomball, TX

52

4a. How many meters are occupied by 8 m3 of fluid ? 4b. How many m3 will it take to fill 230 m of annulus ?

60.325 mm tubing

215.9 mm open hole

EDC, Tomball, TX

Exercises 5. How many meters of annular space would be filled by 24 m3 of fluid in the annular space between 3 strings of 88.9 mm tubing and 339.725 mm, 101.1952 kg/m casing?

6. How many cubic meters of water would it take to fill 152.4 m of annular space between 2 strings of 31.75 mm tubing inside of 114.3 mm, 17.263 kg/m casing?

EDC, Tomball, TX

53

EDC, Tomball, TX

What if you have two different size tubing strings inside of casing or open hole, and you want to find a m3/m factor?

(D2 – d12 – d22) X 0.000 000 7854

D = inside diameter of outside pipe or hole size dn = outside diameter of inside pipes EDC, Tomball, TX

54

1. Given one string of 60.325 mm tubing and a string of 31.75 mm coil tubing inside of 177.8 mm, 35.71594 kg/m casing. What is the m3/m factor for the annular space?

(D2 – d12 – d22) X 0.000 000 7854 D = inside diameter of outside pipe or hole size

dn = outside diameter of inside pipes

EDC, Tomball, TX

Metal Displacement O

How much fluid will the pipe displace from the well, when run in a hole full of fluid. ³ Note: must be open ended pipe

EDC, Tomball, TX

55

Metal Displacement Displacement of pipe in m3 = 0.0001276 x Wt of Pipe (kg/m w/couplings) x (Depth, m)

EDC, Tomball, TX

What is the fluid volume displaced by 610 meters of 244.475 mm, 79.61677 kg/m casing run with an autofill float valve?

EDC, Tomball, TX

56

Dimensions and Strengths

Collapse, Internal Yield and Joint Strength are minimum values with no safety factor.

Used in the field these values should be reduced by a minimum of 20%.

EDC, Tomball, TX

Dimensions and Strengths Terminology for Pipe Connections Box - internal (female) threaded end Pin - external (male) threaded end Flush Joint - connection with male and female threads cut directly into the pipe. NUE - non-upset end EUE - external upset ends - forging of ends on pipe to provide additional thickness for strengthening connections T&C - threaded and coupled - male threads are cut into the pipe and a coupling provides female threads

EDC, Tomball, TX

57

Dimensions and Strengths Terminology for Pipe Connections

EDC, Tomball, TX

Click on Dimensions and Strengths Click on the tubular you are working with.

EDC, Tomball, TX

58

Working with Tubing

Outside diameter

Coupling OD

Grade of pipe Weight of pipe

Drift of pipe EDC, Tomball, TX

Inside Diameter

Working with Tubing

Collapse Internal yield (Burst)

Joint strength

Book value multiplied by 80% = recommended value in the field for collapse, burst, and joint strength. EDC, Tomball, TX

59

1. What is the ID of 219.075 mm, H-40 47.62 kg/m casing ?

2. What is the strongest grade of 60.325 mm tubing ?

3. What is the recommended burst for 114.3 mm, 24.7 kg/m, Type E drill pipe ?

4. What is the recommended tensile load of 73.025 mm, 9.673 kg/m, EUE, N-80 tubing ?

EDC, Tomball, TX

5. What is the ID of 139.7 mm, 34.228 kg/m, N-80 casing?

6. What is the internal yield pressure value in the tables for 244.475 mm, 43603 kg/m, F-25 casing ?

7. What is the recommended internal yield pressure value for 177.8 mm, 56.55 kg/m N-80 casing ?

8. What is the recommended collapse pressure for 508 mm, 158.4895 kg/m, J-55 casing ? EDC, Tomball, TX

60

Cement

EDC, Tomball, TX

Cement or Additive Bulk Volume kg/m3 Specific Gravity Absolute Volume L/kg Absolute Volume m3/kg EDC, Tomball, TX

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Six Important Factors: CEMENT O O O O O O

Density – kg/m3 Yield – m3/t Mix Water – m3/t Mix Fluid - m3/t m3 Volume / Yield = Tonnes Tonnes X Yield = m3 Volume

EDC, Tomball, TX

Under Construction

MIXING WATER (m3/sk)

Type of Cement

YIELD (m3/sk) DENSITY (kg/m3)

MIXING WATER (l/sk) EDC, Tomball, TX

API Recommended Density

62

1. What would be the water requirement and yield for Class C mixed at 1,773.4 kg/m3?

Under Construction EDC, Tomball, TX

2. What is the density and water requirement for Class G with a yield of 0.0323 m3/sk?


63

3. What would be the water requirement for Class H mixed at 2,013 kg/m3?



EDC, Tomball, TX

64


EDC, Tomball, TX

Conversion Factors

EDC, Tomball, TX

65

Cement Slurry Volume Calculations Section 7

Printed: 7/21/2006

EDC, Tomball, TX

API Version

Printed: 7/21/2006

EDC, Tomball, TX

1

Cement Volumes Open Hole

Casing Cross Section Casing / Open- Hole Annulus .

Guide Shoe

Top Wiper Plug

Slide 3

EDC, Tomball, TX

Calculating Cement Volumes for Casing Cementing O O O

There is no float collar in this example. The cement volume is the theoretical volume of the casing-open hole annulus. The theoretical volume of the slurry required to fill the annulus is:

Annular Volume (ft3) = Length (ft) x Volume Factor (ft3/ft) O

The volume factor can be obtained from the eEHB

Slide 4

EDC, Tomball, TX

2

Cement Volumes Example 1

Open Hole 16”

Annular Volume Factor = Annular Volume =

Casing 9 5/8”

800 feet Slide 5

EDC, Tomball, TX


Open Hole 17 1/4”

Casing 10 3/4”


963 feet Slide 7

EDC, Tomball, TX

3


Open Hole 17 1/4”

Casing 10 3/4” 54 #/ft

923 feet Float Collar

963 feet

Annular Volume Factor = Casing Volume Factor = Annular Volume = Shoe Track Volume = Total Slurry Volume = Slide 9

EDC, Tomball, TX

Excess Cement Volume O EXCESS

³ Slurry in addition to the theoretical volume needed to fill the annulus between casing and open hole ³ Open hole size is often given as bit diameter or estimated ³ Does not account for “washouts” ³ Common practice to run excess cement on any pipe job ³ Excess is expressed as a percentage of the slurry required to fill the theoretical volume of the annulus ³ Excess is based on the open-hole annulus volume only ËNot casing-casing annulus or shoe track

Slide 11

EDC, Tomball, TX

4

Calculating Cement Volumes Shoe Joint Volume + Theoretical Annular Volume + Excess Volume (Percentage of open-hole annular volume)

= Total Cement Slurry Volume THIS IS THE TOTAL SLURRY VOLUME!

Slide 12

EDC, Tomball, TX


Open Hole 17 1/4” 40% Excess

Casing 10 3/4” 54 #/ft

923 feet Float Collar

963 feet


EDC, Tomball, TX

5


Lead Slurry 65% Excess

Top of Tail Slurry 1,200 feet

Tail Slurry 20% Excess

Open Hole 20”

Lead Slurry Annular Volume Factor = Annular Volume =

Casing 13 3/8” 72 #/ft

1,460 feet 1,500 feet Slide 15

EDC, Tomball, TX

Cement Volumes Example 5 (continued)


Top of Tail Slurry 1,200 feet


Open Hole 20”

Casing 13 3/8” 72 #/ft

1,460 feet 1,500 feet

Tail Slurry Annular Volume Factor = Casing Volume Factor = Annular Volume = Shoe Track Volume = Tail Slurry Volume = Slide 17

EDC, Tomball, TX

6


Open Hole 20” TOC @ ???? feet

Slurry Data 500 sacks, 15.8 ppg, 1.14 ft3/sk

Casing 13 3/8” 72 #/ft

35% Excess

Now assume we have a fixed amount of cement and find the Top of Cement (TOC).

1,460 feet 1,500 feet Slide 19

EDC, Tomball, TX


Open Hole 20” TOC @ ???? feet Casing 13 3/8” 72 #/ft

35% Excess

1,460 feet

Slurry Data 500 sacks, 15.8 ppg, 1.14 ft3/sk Annular Volume Factor = Casing Volume Factor = Total Slurry Volume = Shoe Track Volume =

1,500 feet Slide 20

EDC, Tomball, TX

7


Open Hole 20” TOC @ ???? feet Casing 13 3/8” 72 #/ft

35% Excess

1,460 feet 1,500 feet

Annular Volume Factor = Casing Volume Factor = Annular Slurry Volume = Height of Slurry = TOC = Slide 22

EDC, Tomball, TX


Printed: 7/21/2006

EDC, Tomball, TX

8

Cement Volumes

Open Hole

Casing Cross Section Casing / Open- Hole Annulus .

Guide Shoe

Top Wiper Plug Slide 25

EDC, Tomball, TX

Calculating Cement Volumes for Casing Cementing O O O

There is no float collar in this example. The cement volume is the theoretical volume of the casing-open hole annulus. The theoretical volume of the slurry required to fill the annulus is:

Annular Volume (m3) = Length (m) x Volume Factor (m3/m) O

The volume factor can be obtained from the eEHB

Slide 26

EDC, Tomball, TX

9


Open Hole 406.4 mm

Casing 244.5 mm


250 m Slide 27

EDC, Tomball, TX


Open Hole 438.2 mm

Casing 273.1 mm


300 m Slide 29

EDC, Tomball, TX

10


Open Hole 438.2 mm

Casing 273.1 mm 80.36 kg/m

288 m Float Collar

Annular Volume Factor = Casing Volume Factor = Annular Volume = Shoe Track Volume = Total Slurry Volume =

300 m Slide 31

EDC, Tomball, TX

Excess Cement Volume O EXCESS

³ Slurry in addition to the theoretical volume needed to fill the annulus between casing and open hole ³ Open hole size is often given as bit diameter or estimated ³ Does not account for “washouts” ³ Common practice to run excess cement on any pipe job ³ Excess is expressed as a percentage of the slurry required to fill the theoretical volume of the annulus ³ Excess is based on the open-hole annulus volume only ËNot casing-casing annulus or shoe track

Slide 33

EDC, Tomball, TX

11

Calculating Cement Volumes Shoe Joint (Track) Volume + Theoretical Annular Volume + Excess Volume (Percentage of open-hole annular volume)

= Total Cement Slurry Volume THIS IS THE TOTAL SLURRY VOLUME!

Slide 34

EDC, Tomball, TX


Open Hole 438.2 mm 40% Excess


288 m Float Collar

300 m


EDC, Tomball, TX

12



Top of Tail Slurry 360 m


Open Hole 508 mm


Lead Slurry Annular Volume Factor = Annular Volume =

448 m 460 m Slide 37

EDC, Tomball, TX



Top of Tail Slurry 360 m


Open Hole 508 mm


448 m 460 m

Tail Slurry Annular Volume Factor = Casing Volume Factor = Annular Volume = Shoe Track Volume = Tail Slurry Volume = Slide 39

EDC, Tomball, TX

13


Open Hole 508 mm TOC @ ???? m Casing 339.7 mm 107.15 kg/m

35% Excess

Now assume we have a fixed amount of cement and find the Top of Cement (TOC). Slurry Data 20.0 tonne, 1901 kg/m3, 0.757 m3/t

448 m 460 m Slide 41

EDC, Tomball, TX



35% Excess

448 m

Slurry Data 20.0 t, 1901 kg/t, 0.757 m3/t Annular Volume Factor = Casing Volume Factor = Total Slurry Volume = Shoe Track Volume =

460 m Slide 42

EDC, Tomball, TX

14



35% Excess

448 m 460 m

Annular Volume Factor = Casing Volume Factor = Annular Slurry Volume = Height of Slurry = TOC = Slide 44

EDC, Tomball, TX

15

Cementing Products Section 8 Part A - Cement Revised June 2006

Printed: 6/12/2006

EDC, Tomball, TX

Cement Products O O O

Part A Part B Part C

Cements Additives Spacers

Slide 2

EDC, Tomball, TX

1

Cements O O

Cement Manufacture and Reactions Portland Cement ³ API Cements ³ Manufactured Light Weight Cements ³ Blended Light Weight Cements

O

Specialty Systems

Slide 3

EDC, Tomball, TX

Oilwell Cement O

Primary purpose ³ Provide a hydraulic bond between the casing and formation for zonal isolation ³ support the casing

Slide 4

EDC, Tomball, TX

2

History of Portland Cement O

Joseph Aspdin, an English mason who patented the product in 1824, named it Portland cement because it produced a concrete that resembled the color of the natural limestone quarried on the Isle of Portland, a peninsula in the English Channel

Slide 5

EDC, Tomball, TX

Complexity of Cement O

O

Portland cement setting chemistry is very complicated It starts the very second that water comes into contact with the dry cement ³ Hydration

O

Research done by BJ revealed 22 separate and identifiable chemical reactions occurring simultaneously while cement was setting Slide 6

EDC, Tomball, TX

3

Complexity of Cement (cont.) O

Cement Properties ³ Production of Oilwell cement is a batch process ³ API specifies ranges for some properties Ë Physical - Chemical - Performance Tests

³ Properties change for each manufacturer Ë Even with the same API cement type

³ Properties change from batch to batch Ë Even with the “same” raw materials and process parameters

³ All cement slurries should be tested Slide 7

EDC, Tomball, TX

Raw Materials Natural O

Calcareous

O

³ Limestone

Argillaceous ³ ³ ³ ³ ³

Ë Sedimentary Ë Metamorphic

³ Cement Rock ³ Shell ³ Coral

Clays Shales Marls Mudstone Slate

Slide 8

EDC, Tomball, TX

4

Manufacturing Process Types O

Dry Process ³ Economical ³ Efficiency

O

Wet Process ³ Reproducible ³ Quality

Slide 9

EDC, Tomball, TX

Manufacturing Process Procedures O O O O O O

Raw Material Proportioned Grinding Heated in Kiln (1,500°C/2,700°F) Converted to Clinker Gypsum (Calcium Sulfate) Added Pulverized

Slide 10

EDC, Tomball, TX

5

Wet Process

Raw Material Proportioned

Pa

Slurry

Iron Ore

Clay

Cement Rock

Water Added Here

d ize ers Ov

Fines

Limestone

Vibrating Screen les rtic

Slurry Pumps

Grinding Mill

To Kiln

Slurry Pump

Slurry is Mixed and Blended Portland Cement Association, 1969

Storage Basins

Slide 11

EDC, Tomball, TX

Dry Process Iron Ore

Clay

Cement Rock

Limestone

To Air Separator

Dust Collectors

Oversized Particles Hot Air Furnace

Fines

Raw Material Proportioned

To Pneumatic Pump

Raw Mix

Grinding Mill

To Kiln

Dry Mixing and Blending Silos

Ground Raw Material Storage

Portland Cement Association 1969

Slide 12

EDC, Tomball, TX

6

Cement Manufacturing Chemical Reactions O

100 - 200 °C ³ Evaporation Of Water

O

400 - 600 °C ³ Dehydroxylation Of Clays

O

800 - 1000 °C ³ Decarbonation Of Limestone

O

1100 - 1300 °C ³ Exothermic Reactions

O

1300 - 1500 °C ³ Sintering Slide 13

EDC, Tomball, TX

Burning Process Raw Material to Kiln

Raw Material is Kiln Burned to Partial Fusion at 1500°C

Coal, Oil or Gas Fuel

Dust Collector

Air

Dust Bin

Fan

Rotating Kiln

Clinker

Cooler

Clinker

Clinker

Material are Stored Separately Gypsum

Clinker and Gypsum are Proportioned and Conveyed to the Final Grinding Mill Portland Cement Association, 1969

Slide 14

EDC, Tomball, TX

7

Grinding Plant Air Separator

Gypsum

Clinker

Dust Collectors

Materials Proportioned

rsiz Ove

les artic ed P

Fines

Grinding Mill

To Bulk Transport, Rail Car and Packaging Plant for use in Oil Wells Ground Cement Storage Portland Cement Association, 1969

Slide 15

EDC, Tomball, TX

Portland Cement Major phases of Clinkers O

C3S - Tricalcium Silicate - Alite 3CaO.SiO2 (idealised): Minor - Al2O3, MgO, P2O5, Fe2O3, Na2O, K2O

O

C2S - Dicalcium Silicate - Belite 2CaO.SiO2 (idealised): Minor - Al2O3, MgO, P2O5, Fe2O3, Na2O, K2O

O

C3A - Tricalcium Aluminate 3CaO.Al2O3 (idealised): Minor - Fe2O3, SiO2, MgO, Na2O, K2O

O

C4AF - Tetracalcium Aluminoferrite - Ferrite 4CaO.Al2O3.Fe2O3 (idealised): Minor - SiO2, MgO, TiO2, Mn2O3.

Slide 16

EDC, Tomball, TX

8

Thin Section Microscopic View of Portland Cement Clinker

Slide 17

EDC, Tomball, TX

Portland Cement Major Phases of Clinkers O

C3S - Tricalcium Silicate - Alite ³ major compound in portland cement (48-65%) ³ contributes to setting and early strength

O

C2S - Dicalcium Silicate - Belite ³ 20 - 25% of clinker ³ slower hydrating than C3S ³ contributes to slower long term strength

Slide 18

EDC, Tomball, TX

9

Portland Cement Major Phases of Clinkers (cont.) O

C3A - Tricalcium Aluminate ³ generally 0 - 8% ³ regulates resistance to sulfate attack ³ promotes rapid hydration ³ controls setting time, rheology, early strength ³ < 3% is considered Highly Sulfate resistant cement

O

C4AF - Tetracalcium Aluminoferrite Ferrite ³ interstitial phase, low reactivity ³ promotes low heat of hydration Slide 19

EDC, Tomball, TX

Other Factors O

Gypsum (Calcium Sulphate, CaSO4) ³ Controls the reaction rate of C3A ³ If no Sulphates are present from the Gypsum a “flash set” will occur

O

Grind ³ Fineness (m2/kg) will influence reaction rates and slurry viscosity Ë Blaine Fineness (Air Permeability) Ë Wagner Fineness (Turbidimeter)

Slide 20

EDC, Tomball, TX

10

Basic Hydration Products C3S + H2O → C-S-H* + Ca(OH)2 C2S + H2O → C-S-H* + Ca(OH)2 2C3A + 18H2O → C2AH8 + C4AH10 2C3A + 32H2O + 3(Ca2+(aq) + SO42-(aq)) → C6AS3H32 C6AS3H32 + 2C3A → 3C4ASH12 C4AF has analogous reactions to C3A, i.e. produces e.g. C6(A,F)S3H32 *C-S-H is an amorphous hydrogel having variable composition in terms of Ca/Si ratio and H2O/SiO2 ratios Slide 21

EDC, Tomball, TX

Heat Flow During The Hydration Of Cement

Heat Flow % Hydration of Cement

% Hydrated Cement Heat Flow Acceleration

Diffusion

Pre-induction Period

40-50% Hydrated Cement

(2%to 3% Hydration)

Induction Period (Silicates Have Low Reactivity During This Period)

min

Deceleration

hours

Setting and Hardening

days

Time

Slide 22

EDC, Tomball, TX

11

Hydration of Cement (C3S) C3S C3S

2 OH-

C-S-H Gel

C3S

H2O Ca2+ H2O

MIX WATER

Ca 2+ 2 OH

H2O

-

Ca 2+ 2 OH Slide 23

EDC, Tomball, TX

Strength Contributions

Slide 24

EDC, Tomball, TX

12

Cement Classification Sulfate API ASTM Percent Rest. Class Type MgO SO3 C3A

Wagner Fineness*

O

A C

I III

6.0 6.0

3.0 4.5

N/A 15.0

160 220

MSR

B G H

II II II

6.0 6.0 6.0

3.0 3.0 3.0

8.0 8.0 8.0

160 180 160

HSR

B C G H

N/A N/A N/A N/A

6.0 6.0 6.0 6.0

3.0 3.0 3.0 3.0

3.0 3.0 3.0 3.0

160 220 180 160 *m2/kg Slide 25

EDC, Tomball, TX

API Cement Classification (Refer to Manual)

Slide 26

EDC, Tomball, TX

13

Portland Cements O

O O O O O O

API cements are portland cement, a type of hydraulic cement, because it sets up under water. API Class A - Similar to ASTM Type I API Class B - Similar to ASTM Type II API Class C - Similar to ASTM Type III API Class G - Similar to ASTM Type IV API Class H - Similar to ASTM Type IV Ultra Fine Cement Slide 27

EDC, Tomball, TX

Portland Cement & CSA Canada O O

O

CSA – Canadian Standards Association Class A similar to CSA “GU” cement or T10 cement Class C similar to CSA “HE” cement or T30 cement

Slide 28

EDC, Tomball, TX

14

Class A O

Normal API Specifications ³ Density ³ Mixing Water ³ Yield

O

15.7 ppg (1878 kg/m3) 46%, 5.19 gal/sk (0.46 m3/tonne) 1.17 cf/sk (0.777 m3/tonne)

Other ³ Surface casing or shallow well cementing ³ Intended use to 6,000 ft, but use caution ³ Similar to ASTME 150, Type I (construction), CSA “GU”, T-10 (construction) Slide 29

EDC, Tomball, TX

NP Cement O

General Information ³ CSA “GU” or T-10 construction cement ³ Similar to API Class A

O

Density Range ³ 1878 kg/m³ to 2000 kg/m³

O

Usage ³ Surface casing or shallow well cementing ³ Intended use to 6,000 ft, but use caution ³ Economical Replacement for API Class A ³ High C3A (OSR) ³ No API Quality Checks Slide 30

EDC, Tomball, TX

15

Type I O

General Information ³ ASTM Construction Cement ³ Similar to API Class A

O

Density Range ³ 15.2 to 15.6 ppg

O

Usage ³ Surface casing or shallow well cementing ³ Intended use to 6,000 ft, but use caution ³ Economical Replacement for API Class A ³ High C3A (OSR) ³ No API Quality Checks Slide 31

EDC, Tomball, TX

Class B O


O

15.7 ppg 46%, 5.19 gal/sk 1.17 cf/sk

Other ³ Surface casing or shallow well cementing ³ Used in Farmington, New Mexico, USA ³ Intended use to 6,000 ft, but use caution ³ Similar to ASTME 150, Type II (construction) ³ Moderate to High Sulfate Resistance Slide 32

EDC, Tomball, TX

16

Class C O

Normal API Specifications ³ Density ³ Mixing Water


³ Yield O

Other ³ ³ ³ ³ ³

Surface casing or shallow well cementing Used in Permian Basin, Rockies & West Coast Intended use to 6,000 ft (1,829 m), but use caution Similar to ASTME 150, Type III (construction) Ordinary to High Sulfate Resistance Slide 33

EDC, Tomball, TX

Type III O

General Information ³ ASTM Construction Cement ³ Similar to API Class C

O

Density Range ³ 14.4 to 14.8 ppg (Dependant on the Cement Fineness)

O

Usage ³ ³ ³ ³ ³

Surface casing or shallow well cementing Intended use to 6,000 ft, but use caution Economical Replacement for API Class C High C3A (OSR) No API Quality Checks Slide 34

EDC, Tomball, TX

17

HE Cement O

General Information ³ CSA “HE” or T-30 construction cement ³ Similar to API Class C

O

Density Range ³ 1776 kg/m³ (Dependant on the Cement Fineness)

O

Usage ³ ³ ³ ³ ³

Surface casing or shallow well cementing Intended use to 6,000 ft, but use caution Economical Replacement for API Class C High C3A (OSR) No API Quality Checks Slide 35

EDC, Tomball, TX

Class G O


O


Other ³ ³ ³ ³ ³ ³

All-purpose cement Use: Worldwide Intended use to all depths, with additives Finer grind than Class H Used in largest geographical area in N. America Most used cement class, world-wide

Slide 36

EDC, Tomball, TX

18

Class H O

O

Normal API Specifications ³ Density 16.5 ppg (1977 kg/m3) ³ Mixing Water 38%, 4.28 gal/sk (0.38 m3/t) ³ Yield 1.05 cf/sk (0.697 m3/t) Other ³ ³ ³ ³ ³ ³ ³ ³

All-purpose cement Use: E. and S. of Rockies; Venezuela Not manufactured in Canada Intended use to all depths, with additives Coarser grind than Class G More often mixed at 15.6 - 15.7 ppg than at 16.5 ppg Absolute minimum 15.5 ppg w/o additives Most-used (by volume) cement in North America Slide 37

EDC, Tomball, TX

Ultrafine System International O

A fine grind penetrating cement ³ Early strength development ³ Lower density than API cement Ë Normally 12.5 ppg (1,498 kg/m3)

³ Low permeability O

Provides seal or squeeze in problem areas:

O

³ thief zones, water zones, gas zones, casing leaks or gravel packs Patent Issues (Halliburton) ³ Microcem 1000 (Canada) ³ Ultrafine C Slide 38

EDC, Tomball, TX

19

Microcem 1000 Canada O O

O O

Ultra fine cement Composed of ultra fine cement and blast furnace slag Density from 1,500 to 1,723 kg/m³ Used in Canada

Slide 39

EDC, Tomball, TX

Microcem 2000 Canada O O O

Ultra fine cement Composed of ultra fine cement and fly ash Used in Canada

Slide 40

EDC, Tomball, TX

20

Light Weight Cements O

Manufactured light weight cement ³ Made as per Portland cements ³ With added light weight aggregate Ë kiln-fired shale

³ Example: TXI Lightweight or TLW Ë SG of 2.8 (vs 3.14 of API cements) O

Blended light weight cement (Field Blends) ³ Light weight aggregate blended after manufacture Ë API or Construction cement with Fly Ash, Bentonite, MPA’s, etc

Slide 41

EDC, Tomball, TX

Light Weight Cements: Manufactured Light Weight O

TXI Lightweight or Trinity Light Wate (TLW) ³ High temperature stable Ë Up to 3500 F (180 °C) without additional silica

³ Density range 12.0 to 14.2 ppg (1,380 to 1,640 kg/m3) Ë No extenders needed, just add water Ë Canada density range (1400 to 1760 kg/m3)

³ ³ ³ ³

Good slurry properties Excellent compressive strengths Sulfate-resistant Compatible with API cement additives

Slide 42

EDC, Tomball, TX

21

Light Weight Cements: Blended Light Weight O O O O

O

O

Fly Ash Cement (FAC) O MaxLite, “I” and “C” Extreme Lite and “II” Econofill “A”, “C”,“H”, O O “ AZ”, “CZ”, “HZ”, O “NE” Fort Worth Basin O Premium BJ HT Lite Ref.:

Premium Lite, “F”, “Plus”, “Plus F”, “HS”, II, and “II HS” Premium NE, and “F” Tuflite, “II” and “Ultra” Arkoma Lite, and “II” Surf Lite, and “II”

Slide 43

EDC, Tomball, TX

Lightweight Cements Canadian Blended Cements O O O O O O O

Fill-Lite BVF SpectraCem MaxxCem NPS Tru-Lite Poz L/Portland

Slide 44

EDC, Tomball, TX

22

Fly Ash Cements O

Fly Ash Cements (FAC) ³ Economical Extended Slurries ³ Densities as low as 12.1 ppg ³ Use a nomenclature of shown below ³ Refers to Fly Ash : Cement : Bentonite (or Gel) Ë Cement Type should be specified

³ See also eEHB

15:85:8 50:50:2 35:65:6 50:50:0 40:60:8 Slide 45

EDC, Tomball, TX

Fly Ash Cement Calculations O O O

1st number is the percent of a 74 lb sack of Fly Ash 2nd number the percent of a 94 lb sack of API cement 3rd number is the percent of gel (bentonite) based on the blended sack weight (fly ash and cement) Example: 35:65:6 35% Fly Ash x 74 lb/sk = 25.9 lbs 65% Cement x 94 lb/sk = 61.1 lbs Blended Sack Weight = 87.0 lbs 6% BWOC Bentonite x 87.0 lbs/sk = 5.22 lbs

Slide 46

EDC, Tomball, TX

23

Fly Ash Cements Calculations: Canada O O O O O O O

Absolute volume ratios of pozzolan (fly ash) and cement and percentage of gel 1st term fly ash ratio 2nd term cement ratio 3rd term is percent of gel based on cement and fly ash 1:1:0, 1:1:2, 1:1:4 etc. 2:1:0, 2:1:2, 2:1:4, etc Based on 1 tonne (1000 kg) dry blend of flay ash and cement Slide 47

EDC, Tomball, TX

Multi-Dense (Canada) O

Description ³ Manufactured Lite Wate plus API cement (usually A or H), bulk blended in the sack ³ Ratios of either 1:1, 1:2 or 2:1

O

Application (Primary Effect on Slurry) ³ Wide density range - - 12.7 to 15.0 ppg (1520 to 1800 kg/m³) ³ Excellent compressive strengths conditions

Slide 48

EDC, Tomball, TX

24

Multi-Dense (Canada) (cont.) O

Side or Secondary Effects ³ Very compatible with all cement additives ³ Easily mixed slurry

O

Special Notes ³ Ratios always written in this order: TLW:Portland cement ³ Can be modified to fit all well conditions ³ Terminology no longer commonly used, but still valid

Slide 49

EDC, Tomball, TX

Specialty Systems O

O O O O O O

BFS Slurries

O

³ Slagment™

O

Cold-Set DeepSet™ Foamed Cement Liquid Stone™ Lite-Set™ FlexSet™

Magne Plus Magnelink ³ International

O O

PolyFX Thixotropic Systems ³ ³ ³ ³

O

Sure Fill Sure Plug Thixofil Thixolite

Texas TRC 100 Slide 50

EDC, Tomball, TX

25

BFS Slurries O

(Blast Furnace Slag) under license from Shell A non-metallic by-product of the steel-making process used in converting drilling mud to cement ³ Not a Portland Cement

O

O O O

O

Compressive strength and bonding properties are excellent While not applicable to every well May have cost benefits Does not require dry blending, slag-mud slurries are mixed and pumped using standard equipment Highly resistant to sulfated and corrosive waters

Slide 51

EDC, Tomball, TX

Slagment™ O O

O

O O

O

A Blend of BFS and Type I Cement Used in Areas That Have an Economical Source of BFS Provides an Alternative to Portland Cement Where Cement Quality Is a Concern Can Be Used in Place of Class G or H Cement Slurry Properties Similar to Portland Cement Are Achievable Primarily used in international

Slide 52

EDC, Tomball, TX

26

Cold-Set O

Description ³ Can set at 20°F without freezing ³ High early compressive strength ³ Effective insulation (low thermal conductivity). ³ Blend of Class G, Gypsum and Calcium Chloride ³ Three systems: Ë Cold-Set I at 15.3 ppg (1830 kg/m3) Ë Cold-Set II at 14.95 ppg (1790 kg/m3) Ë Cold-Set III at 12.2 ppg (1460 kg/m3)

Slide 53

EDC, Tomball, TX

DeepSet™ O

General Information ³ Used to control shallow water flow in deep water drilling environments, often foamed

O

Ingredients

BJ Services Deep Set

³ Cement Ë Moderate to High Sulfate resistance

³ MPA-1 & BA-10/BA-10A ³ CD-33 & Sodium Metasilicate ³ Calcium Chloride O

Usage ³ 15.2 - 15.6 ppg w/Class A (1820 to 1870 kg/m3) ³ 14.2 - 14.8 ppg w/Class C or Type III (1700 to 1770 kg/m3) Slide 54

EDC, Tomball, TX

27

Foamed Cement O O

Low density cements Foamed with N2 ³ As low as 4 ppg (480 kg/m3)

O

Usable compressive strengths

20Q Foam Cement

³ above 8 ppg (960 ³ below 35% Nitrogen

kg/m3)

O O O

Lost Circulation Weak Zones Slurry stability ³ Requires foamer and stabilizer Slide 55

EDC, Tomball, TX

LiquidStone™ O

General Information ³ Patented Storable Liquid Cement Blend, That Can Be Stored on the Rig for an Extended Period of Time, Then Activated and Pumped to Form an Annular Seal.

O

Ingredients ³ Slurried Portland Cement ³ Suspending agent ³ Retarder ³ Other Additives to Control Slurry Properties Slide 56

EDC, Tomball, TX

28

Lite-Set™ O

Low density system based on LW-6 ³ Prevents lost circulation ³ Superior strength Ë Compared with conventional extenders at the same density

³ Compatible with API cements and most cement additives

Slide 57

EDC, Tomball, TX

TM

FlexSetTM Systems O

Systems With Enhanced Mechanical Properties ³ Can “Adapt” to Well Deformations. ³ Prevent the Loss of Zonal Isolation. ³ Combinations of PVAs, MPAs, FL, LW Additives ³ Improved Flexural and Tensile Strength at Least 20% Over a Conventional Slurry at the Same Density. ³ The Result of Our Studies on Mechanical Properties of Cement. Slide 58

EDC, Tomball, TX

29

Magne Plus™ O

Description ³ Mixture of magnesium and calcium compounds ³ used from 140 °F (60 °C) to 240 °F (93 °C)

O

Application ³ Setting plugs across potential pay zones ³ Lost circulation ³ Other activities above pay zone

O

Completely soluble in Acid (15% HCl) ³ non-damaging to production zones

Slide 59

EDC, Tomball, TX

Magne Plus™ (cont.) O

Side or Secondary Effects ³ Will harden in most muds and brines

O

Special Notes ³ Normal density range: 13.0-14.0 ppg (1560 to 1680 kg/m3) ³ Requires special additives Ë Retarders: R-9 or Boric Acid Ë Dispersant: Sodium Gluconate

O

Magne Plus™ LT ³ Similar to regular Magne Plus ³ Used below 140 °F (60 °C) Slide 60

EDC, Tomball, TX

30

Thixotropic Systems O

Definition: ³ The property exhibited by certain gels of becoming fluid when stirred or shaken and returning to the semisolid state upon standing.

O

Used for lost circulation zones ³ Set up quickly to “heal” lost circulation ³ In plug cementing, harder cement plugs can then be added as needed

Slide 61

EDC, Tomball, TX

Sure Fill O

Temperature Range ³ 80 to 130° F (30 to 50 °C) BHCT

O

Additives ³ Class G or H base ³ Gypsum ³ Calcium Chloride

O

Normally mixed at 12.5 to 13.5 ppg (1500 to 1620 kg/m3)

Slide 62

EDC, Tomball, TX

31

Sure Plug O

Temperature Range ³ up to 300° F (150 °C) BHCT

O

Additives ³ ³ ³ ³

O

Class G or H base Dispersant Sodium Metasilicate (SMS) Retarder, as needed

Mixed at Normal API Density

Slide 63

EDC, Tomball, TX

Thixofil O

Temperature Range ³ 120 to 200° F (50 to 90 °C) BHCT

O

Additives ³ Class G or H base ³ Thixofil Additive Ë Combination of Bentonite (Gel) and Sodium Metasilicate (SMS)

³ Retarder, R-11, as needed O

Normally mixed at 14.5 ppg (1740 kg/m3) Slide 64

EDC, Tomball, TX

32

Thixolite O

Temperature Range ³ up to 240° F (115 °C) BHCT

O

Additives ³ Commercial Light Weight Cement ³ Gypsum (A-10) ³ Attapulgite Clay

O

Usage ³ Lost circulation ³ 11.0 to 13 ppg (1320 to 1560 kg/m3) Slide 65

EDC, Tomball, TX

Texas TRC 100 O

General Information ³ Lightweight filler cement for shallow, low temperature, surface casing applications

O

Ingredients ³ ³ ³ ³

O

Class C base, 6% Bentonite 4% CaCl2 (A-7P), 4% KCl 5 lb/sk Hydrated Lime 124% Water (12.27 ppg, 1470 kg/m3)

Usage ³ Lightweight filler cement for shallow, low temperature, surface casing applications ³ Rapid early compressive strengths Slide 66

EDC, Tomball, TX

33

Specialty Cements Canada O O O O O O O

BVC-30 Thix-Mix Polarset Rapidset Thermal 40F LiteCem Foam Cement

O O O

O

Nowblock Versablock Thermal 40M THIXMIX NPS-1

Slide 67

EDC, Tomball, TX

BVC-30 Canada O

O

O O O O

Blend of cement, gypsum, gel, and calcium chloride Bulk blend in 1 tonne (1000 kg) formulation Thixotropic properties Lower density mixed at 1714 kg/m³ Accelerated Used in shallow wells primarily in south eastern Alberta Slide 68

EDC, Tomball, TX

34

Thix-Mix Canada O O

O O O

Composed of cement and gypsum Bulk blend in 1 tonne (1000 kg) formulation Available as Thix-Mix NP or Thix-Mix G Thixotropic cement Mixed at 1741 kg/m³

Slide 69

EDC, Tomball, TX

Polarset Canada O

O

O O O

Mixture of cement, gypsum and sodium chloride Bulk blend in 1 tonne (1000 kg) formulation Used in cementing permafrost Mixed at 1881 kg/m³ Most often density is reduced with LW-6 ceramic spheres

Slide 70

EDC, Tomball, TX

35

Rapidset Canada O O

O O

Blend of cement and gypsum Bulk blend in 1 tonne (1000 kg) formulation Right angle set Used primarily to prevent gas or fluid inflow or for very short drill out times

Slide 71

EDC, Tomball, TX

Thermal 40F O O

O

Composed of cement and silica Bulk blend in 1 tonne (1000 kg) formulation For use when temperature exceeds 110°C

Slide 72

EDC, Tomball, TX

36

LiteCem Canada O

O

O O

Family of blends composed of cement, LW-6, EXC, A-11, A-9 Bulk blends in 1 tonne (1000 kg) formulations Densities from 1100 to 1500 kg/m³ Retarded with R-55

Slide 73

EDC, Tomball, TX

Foam Cement Canada O

O O

Lightweight cement created by foaming with nitrogen gas AF-1 foaming agent @ 5.0 litre/m³ Recommend an additional foam stabilizer be included such as, NFL-2, FL-5, gel or EXC be used as well

Slide 74

EDC, Tomball, TX

37

Nowblock Canada O

O O O O O

Composed of cement, EXC and Silica in TS formulation Nowblock G 5, Nowblock G 10 Nowblock NP 5, Nowblock NP 10 Nowblock TS 5, Nowblock TS 10 Accelerated with calcium chloride Applications for lost circulation control, water and gas inflow control Slide 75

EDC, Tomball, TX

Versablock Canada O

O O O O O

Composed of cement, EXC, A-11 and silica in TS thermally stable formulation. Versablock G 5 and Versablock G 10 Versablock NP 5 and Versablock NP 10 Versablock TS 5 and Versablock TS 10 Accelerated with calcium chloride Applications for lost circulation control, water and gas inflow control Slide 76

EDC, Tomball, TX

38

Thermal 40M Thix-Mix Canada O O

O O

O

Blend of cement, silica and gypsum Bulk blend in 1 tonne (1000 kg) formulation Slurry density 1800 kg/m³ Thermally stable cement for use where well temperatures will or can exceed 110°C Thixotropic cement to prevent slurry fall back Slide 77

EDC, Tomball, TX

NPS-1 Canada O

O

O O

Blend of cement, fly ash, fumed silica, A11, EXC and CD-32 Bulk blend in 1 tonne (1000 kg) formulation Slurry density 1760 kg/m³ Used primarily as production or tail in cement

Slide 78

EDC, Tomball, TX

39

Cementing Products Section 8 Part B - Additives Revised June 2006

Printed: 6/12/2006

EDC, Tomball, TX




Slide 2

EDC, Tomball, TX

1

Additives O O O O O O O O

Effects of Additives Accelerators Retarders Fluid Loss Control Dispersants Gas Flow Control Bonding Agents Free Water Control

O O

O O

O

O O

Extenders Lost Circulation Materials (LCM) Weighting Materials Multi-Purpose additives Strength Retrogression Materials Foam Preventers Spacers & Flushes Slide 3

EDC, Tomball, TX

Effects of Additives O

Primary Effect ³ Predictable in a general sense ³ Ex.: Accelerator makes slurry set faster

O

Secondary Effect ³ Occurs with most additives ³ May or may not be advantageous ³ Ex.: Lignosulfonate retarders tend to thin slurry

O

Synergistic Effect ³ Results from two additives ³ Ex.: Some Dispersants and Fluid Loss Additives

Slide 4

EDC, Tomball, TX

2

Additive Properties O

Desirable attributes ³ Consistent response with all cements ³ Linear response v/s concentration ³ Little effect on other slurry properties ³ No interference with other additives ³ Easy to blend or mix ³ Low cost ³ Low toxicity

Slide 5

EDC, Tomball, TX

Slurry Design O O

Not an exact science Density ³ First parameter considered

O

Product choice will then depend on: ³ Temperature ³ Other slurry requirements Ë Fluid Loss Ë Viscosity

³ Cement Mechanical Properties ³ Other Special Requirements Slide 6

EDC, Tomball, TX

3

Accelerators O

Primary use ³ Optimize WOC time while allowing time for slurry placement Ë Accelerate strength development ¸ 500 psi compressive strength to drill shoe

Ë Will shorten initial hydration period (thickening time) ¸ Pump Time plus Safety Factor (1 hour)

³ Generally required below 100°F

Slide 7

EDC, Tomball, TX

Accelerators O

Secondary effects ³ Some “accelerators” are used primarily for their “secondary” effects ! Ë Ë Ë Ë Ë

Counteract retardation Stabilize the slurry Reduce free water Prevent formation damage Thixotropic properties

³ Do not generally change long term strength

Slide 8

EDC, Tomball, TX

4

Accelerators: BJ Products (Primary Effects) O

Accelerate strength development and shorten initial hydration period ³ Mostly inorganic salts Ë Ë Ë Ë

A-2 (Sodium Metasilicate, SMS) A-3L (Sodium Silicate) A-5 (Sodium Chloride, NaCl) A-7 & A-7L (Calcium Chloride, CaCl2)

Ë Ë Ë Ë Ë

A-9 (Potassium Chloride, KCl) A-10 (Gypsum) A-11 (Hydrated Lime) AEF-100L T-40L

¸ Most Common

Slide 9

EDC, Tomball, TX

Accelerators: BJ Products (Secondary Effects) O

Counteract Retardation ³ A-2 (Sodium Metasilicate, SMS) ³ A-3L (Sodium Silicate) ³ A-9 (KCl)

O

Stabilize the Slurry ³ A-2 & A-3L (Sodium Metasilicate) ³ A-10 (Gypsum), T-40L

O

Prevent Formation Damage ³ A-5 (NaCl) ³ A-9 (KCl) Slide 10

EDC, Tomball, TX

5

A-7, Calcium Chloride O

Description ³ Chemistry shorthand = CaCl2 ³ Available in white flake, pellet or powder ³ Also available as a liquid (A-7L)

O

Application (Primary Effect on Slurry) ³ Accelerates cement setting time ³ Results in high early compressive strength ³ Usual concentrations 1 to 4% BWOC (typically 2%)

O

Side or Secondary Effects ³ Generates a lot of heat ³ Increases slurry consistency (viscosity) ³ Can cause premature hydration (“flash set”) Slide 11

EDC, Tomball, TX

A-7, Calcium Chloride

Slide 12

EDC, Tomball, TX

6

A-7, Calcium Chloride

Slide 13

EDC, Tomball, TX

A-5, Sodium Chloride O

Description ³ chemistry shorthand = NaCl ³ common table salt

O

Application (Primary Effect on Slurry) ³ used for cementing across salt zones or salt domes ³ 3% to 37.2% (saturated) BWOW

O

Side or Secondary Effects ³ Slightly expansive, improves bonding ³ Slight acceleration below 11% BWOW & retardation above 18% BWOW ³ Decreases slurry consistency (viscosity) causes foaming Slide 14

EDC, Tomball, TX

7

A-9, Potassium Chloride O

Description ³ Chemistry shorthand = KCl ³ Available in several dry forms

O

Application (Primary Effect on Slurry) ³ Protects fresh water sensitive zones ³ 3% to 5% BWOW most common

O

Side or Secondary Effects ³ Slightly expansive, improves bonding ³ Mild acceleration in low percentages ³ Decreases slurry consistency (viscosity) Slide 15

EDC, Tomball, TX

O

A-2, Sodium Metasilicate (EXC, Canada) and A-3L, Sodium Silicate (Liquid) (EXC-L, Canada) Description ³ white powder (A-2) or viscous clear/white liquid (A-3L) ³ also known as SMS (A-2) or SSL (A-3L)

O

Application (Primary Effect on slurry) ³ Allows addition of more water in a slurry, giving a higher yield and lower density, while maintaining slurry integrity. Usually lowers cost per cubic foot of yield. ³ Excellent extender Slide 16

EDC, Tomball, TX

8

O

A-2, Sodium Metasilicate (EXC, Canada) and A-3L, Sodium Silicate (Liquid) (EXC-L, Canada) (cont.) Side or Secondary Effects ³ lowers compressive strengths somewhat ³ provides some thixotropic properties ³ mild accelerator ³ excellent free water control

O

Special Notes ³ normal percentages: 1, 2, 3 or 4 (dry) BWOC (A-2) ³ temperature limitation of 150 °F (65 °C) Slide 17

EDC, Tomball, TX

Retarders O

Function ³ Allow sufficient pumping time for slurry placement Ë Interferes with kinetics of cement hydration

O

Chemical Types ³ Lignosulfonates (Most Common) ³ Organic Acids ³ Saccharides ³ Cellulose Compounds ³ Organophosphonates (High Temperature) ³ Inorganics Slide 18

EDC, Tomball, TX

9

Retarders (cont.) O

Lignosulfonates ³ Most common chemical family used as Retarders ³ Sodium or Calcium Lignosulfonates or blends ³ Tend to thin or disperse slurries Ë Normally a desirable effect

³ Best with Low C3A cements ³ Temperature range to 380 °F (193 °C) ³ 0.1 to 2.0 % BWOC or 0.05 to 0.5 gps ³ Threshold effect ³ Inexpensive Slide 19

EDC, Tomball, TX

Retarders (cont.) O

Retarder Types ³ Low temperature ³ High temperature ³ 180 to 220 °F (82 to 104 °C) can be a challenge in slurry design Ë Falls between High and Low temperature Ë More testing is usually required Ë Results may be harder to predict

Slide 20

EDC, Tomball, TX

10

BJS Retarders O

R-3 ³ Economical low temperature lignosulfonate (to 225 °F, 107 °C) ³ Most common retarder in US

O

R-7 ³ Organic acid specifically for Cold Set systems (to 100 °F, 38 °C) ³ Also called Cold Set Retarder

O

R-7C ³ Citric Acid specifically for Permafrost and Gypcem blends in Canada @ 40 – 100 °F (5 to 40 °C) BHCT ³ Use 0.1 to 0.2% BWOC ³ Strongly disperses

O

R-8, R-8L ³ High temperature ligonsulfonate (200 to 400 °F, 93 to 204 °C) ³ Widely used, Concentration sensitive below 300 °F (149 °C) Slide 21

EDC, Tomball, TX

BJS Retarders (cont.) O

R-9 (R-35) ³ Inorganic intensifier (Sodium Borate) for R-8 ³ 300 to 400 °F (149 to 204 °C) ³ Use 1.5% per 1% of R-8

O

R-18 ³ Inorganic retarder for thixotropic systems (100 to 240 °F, 38 to 116 °C) ³ Compatible with A-2, A-10 and HEC fluid loss additives

O

R-19 (R-120C) ³ Sodium Gluconate, strongly disperses ³ 248 to 338 °F (120 to 170 °C) ³ Do not use below 230 °F (110 °C)

O

R-21, R-21L ³ Low to medium temperature lignosulfonate (to 240 °F, 116 °C)) ³ Widely used, Not compatible with A-2 Slide 22

EDC, Tomball, TX

11


SR-31L ³ High temperature organophosphonate synthetic (230 to 380 °F, 110 to 193 °C) ³ Compatible with most additives and NaCl or seawater systems

O

SR-35L ³ High temperature organophosphonate synthetic (200 to 500 °F, 93 to 260 °C) ³ Strong dispersant, recommended weighting material W-10

O

R-6 (Diacel LWL) ³ CMHEC (CarboxyMethyl HydroxyEthyl Cellulose) (180 to 250 °F, 82 to 121 °C) ³ Increases slurry viscosity, aids fluid loss control ³ Used in low density systems where fluid loss control is needed Slide 23

EDC, Tomball, TX


A-5, Sodium Chloride ³ Not used primarily as a retarder ³ Will retard at over 18% BWOW and 200 °F (93 °C)

O

Granulated Sugar ³ Used primarily to prevent cement from setting at surface ³ Typical loading 10 to 20 lb per bbl of slurry

O

R-5S ³ Low temperature lignosulfonate (to 240 °F, 116 °C) ³ Incompatible with A-2

O

R-10L ³ Low temperature lignosulfonate liquid (to 210 °F, 99 °C) ³ Environmentally friendly Cat. E for International operations

Slide 24

EDC, Tomball, TX

12


R-12L ³ Low to medium temperature lignosulfonate liquid (to 240 °F, 116 °C) ³ Incompatible with A-3L

O

R-21LS ³ Not the same chemistry as R-21L

O

R-55 (Canada) ³ Chemically modified lignosulfonate ³ 40 to 200 °C ³ Similar to R-8

Slide 25

EDC, Tomball, TX

Fluid Loss: A Definition O

O

O

Fluid loss is the water lost from the cement slurry to the formation during slurry placement As the fluid is forced out of the cement, the density of the slurry increases and changes the slurry characteristics (Micro Fluid Loss) Emphasis should be placed upon the fact that fluid loss is a rate and not a volume

Slide 26

EDC, Tomball, TX

13

Fluid Loss Rates O

Neat cement has a fluid loss rate in excess of 1000 cc/30 min. Varying concentrations of fluid loss additives give varying fluid loss rates. The fluid loss numbers listed below and their interpretations are generally accepted 0 to 50 cc/30 min 50 to 100 cc/30 min 100 to 200 cc/30 min 200 to 500 cc/30 min 500 to 1000 cc/30 min 1000 plus cc/30 min

gas migration ultra low good moderate fair no control Slide 27

EDC, Tomball, TX

How Fluid Loss Chemistry Works O O

O

O

Filter cake development can be viewed as a process of filtration Under differential pressure the cement particles suspended in the slurry are filtered by permeable strata The deposited solids form a filter cake whose structure is influenced by particle size, particle charge, packing efficiency of the particles and degree of particle compression Once this framework of solids is built, further reduction in filter cake permeability is dependent on the action of the fluid loss polymers Slide 28

EDC, Tomball, TX

14

How Fluid Loss Chemistry Works (cont.)

Slide 29

EDC, Tomball, TX

Fluid Loss Additives O

Function ³ To maintain a constant solid:liquid ratio in cement slurries during placement and to the setting time. ³ This ensures consistent rheological properties, thickening time and lowers the risk of wellbore invasion

Slide 30

EDC, Tomball, TX

15


Principal generic types ³ Cellulose derivatives Ë FL-52, FL-54, FL-24, FL-25, FL-26, FL-19L (D-19L)

³ Synthetic polymers Ë FL-45LS, BA-56, BA-10/10A, BA-11, BA-9L, FL-62, FL-63, FL-66/66L, FL-67L, FLR-1/1L, BJ Ultra

³ Latex (SBR) Ë BA-86L (primarily international use - patent issue)

Slide 31

EDC, Tomball, TX


Mechanisms of action ³ Viscosification ³ Wall building/pore plugging ³ Adsorption ³ Multiphase phenomena

Slide 32

EDC, Tomball, TX

16

Effect of Improper Fluid Loss Additive O

O

O

Too little additive will cause higher fluid loss than desired Too much additive will cause a high viscosity slurry and increase costs Wrong additive: ³ May not control fluid loss ³ May yield unpumpable slurry ³ May give excessive set time

Slide 33

EDC, Tomball, TX

Fluid Loss Control (cont.) O O O O O O O O

D-19L (FL-19L) Diacel LWL FL-24 FL-26 FL-28 FL-45LS FL-54 FLR-1 & FLR-1L

O O O O O O O

BA-10 & BA-9L FL-25 & FL-25S FL-52 FL-62 FL-66 & FL-66L FL-63 & FL-67L BJ Ultra

Slide 34

EDC, Tomball, TX

17

Diacel LWL® O

O

O

O

A white powdered cellulose material used to reduce fluid loss from cement slurries. In addition to excellent fluid loss control, it is an effective retarder up to 240 °F (115 °C) BHCT. Uniform and predictable retardation as well as excellent solids support in a slurry are two of the most important properties. Can be used as a high-temperature fluid loss additive when used with CD-32 to reduce resulting slurry viscosity Diacel is a registered trademark of Drilling Specialties Slide 35

EDC, Tomball, TX

FL-5 Canada O O O O

Synthetic polymer Provides very low fluid loss 20 to 40 cc/30 minutes Cannot be used with CD-31 ³ Use CD-32 instead

O

Fluid loss for cement at temperatures < 60 °C BHCT

Slide 36

EDC, Tomball, TX

18

FL-24 (International) O

Fluid Loss Additive Blend for South America ³ Medium to high temps

Slide 37

EDC, Tomball, TX


Fluid Loss Additive Blend for South America

Slide 38

EDC, Tomball, TX

19


Fluid loss control for cement at medium temperatures

Slide 39

EDC, Tomball, TX

FL-45LS (International) O

Anionic Blend of Synthetic polymer and a Surfactant ³ Low to medium temperature

Slide 40

EDC, Tomball, TX

20


O

O O

CMHEC base cement fluid loss agent, retarder, and spacer additive Effective to 240 °F (115 °C) with predictable retardation, excellent solid support Needs accelerator below 200 °F (95 °C) 0.3 to 1% BWOC

Slide 41

EDC, Tomball, TX

Fluid Loss Flow Chart FL-52

FL-25 BA-56

CD-32 FL-62

BA-10 Slide 42

EDC, Tomball, TX

21

FL For Critical Conditions

FL-66 & L FL-63 FL-67L FLR-1L FLR-1

HIGH SALINITY HIGH TEMPERATURE 80 °F (27 °C) to ± 400 °F (204 °C)

Slide 43

EDC, Tomball, TX

FL-25 O

O

O

O O O

An all-purpose, salt-tolerant fluid loss additive formed by FL-52 and CD-32 Provides exceptional fluid loss control across a wide range of temperature and salinity conditions Controls the rate of fluid loss by limiting filtrate loss to permeable strata Good compressive strength development Excellent free water/solids support Moderately retarding and lower viscosity than FL52 Slide 44

EDC, Tomball, TX

22

FL-25S O

General purpose cement fluid loss agent for primary and remedial cementing ³ Used in international

Slide 45

EDC, Tomball, TX

FL-52 O

O

O

A water-soluble, high molecular weight fluid loss additive for use in medium and low density slurries Can be used in both fresh water and saline environments High purity and optimized molecular weight distribution yields an extremely efficient fluid loss additive

Slide 46

EDC, Tomball, TX

23

FL-62 O

O O O

O

A non-retarding, dry blend of BA-10 and CD-32 used to control fluid loss during primary and squeeze cementing operations Good early compressive strength development Good slurry integrity and stability Superior bond logs even in the presence of highpressure gas zones Side or Secondary Effects ³ Not compatible with bentonite ³ Not compatible with borates ³ Not compatible with salts Slide 47

EDC, Tomball, TX

FL-63, FL-67L O

O

O O O

Polymeric cement fluid loss and gas migration control agent Applicable at BHCT from 60 to 350 °F (15 to 180 °C) Stabilizes emulsion in latex-based slurries Good salt tolerance Widely used in coiled tubing cement applications ³ Low inherent slurry viscosity Slide 48

EDC, Tomball, TX

24

FL-66, FL-66L O

O

O O

Polymeric cement fluid loss and gas migration control agent Applicable at BHCT from 60 to 350 °F (15 to 180 °C) Stabilizes emulsion in latex-based slurries Good salt tolerance

Slide 49

EDC, Tomball, TX

FL-77 Canada O O O O

Synthetic polymer Provides very low fluid loss 20 to 40 cc/minutes Cannot be used with CD-31 ³ Use CD-32 instead

O

Primarily used over FL-5 in higher temperature applications

Slide 50

EDC, Tomball, TX

25

FLR-1, FLR-1L O

O

Polymeric cement fluid loss and gas migration control agent Applicable at BHCT from 200 to 500+ °F (90 to 260+ °C) ³ Below 200 °F (90 °C) BHCT retards strongly

O

O

Excellent salt tolerance up to salt saturation Disperses

Slide 51

EDC, Tomball, TX

NFL-2 Canada O

O

Blend of fluid loss polymers and dispersant Primarily cellulose based fluid loss agent

Slide 52

EDC, Tomball, TX

26

Dispersants O

Definition ³ Adjust the particle surface charge on the cement grain to obtain the desired flow properties of the slurry

O

Function ³ ³ ³ ³ ³ ³ ³

To reduce critical pump rates To minimize friction pressures To improve surface mixability To offset gellation To improve fluid loss control To enhance retarder activity To densify slurries

Slide 53

EDC, Tomball, TX

Dispersants (cont.) O

Principal Generic Types ³ Synthetic Sulphonated Polymers Ë CD-31, CD-31L, CD-32, CD-32L, CD-33, CD-33L

³ Sugars/organic Acids Ë R-23L, R-7, D-Glucono-d-Lactone, Sodium Gluconate, Citric Acid

³ Lignins Ë R-1, R-3, R-8, R-8L, R-5, R-12L, R-15L

³ Inorganics Ë NaCl, SAPP

Slide 54

EDC, Tomball, TX

27

Dispersants (cont.) O

Mechanisms of action ³ Electrostatic Repulsion Ë Adsorption of polyanion on positively charged sites on cement hydrates Ë Neutralization of electrostatic charges at cement grain surface Ë Diminished attractive forces (or net repulsive forces) between particles

³ Alteration of interstitial ion balance Ë Adsorption

Slide 55

EDC, Tomball, TX

Dispersant: Types (cont.) O

Polynaphthalene Sulfonates (PNS) ³ Most widely used ³ 0.2 to 1.5% bwoc ³ Higher concentration w/salt ³ Dry and liquid (CD-31 and CD-32) ³ Stable to 500 °F (260 °C)

Slide 56

EDC, Tomball, TX

28

Dispersant: Types (cont.) O

Poylstyrene Sulfonate - CD+500 ³ Costly ³ Retardive

Slide 57

EDC, Tomball, TX

CD-31, CD-31L & CD-31LS O

Description ³ Sodium salt sulfonated naphthalene condensate

O

Application (Primary Effect on slurry) ³ Disperse the cement so turbulent flow can be achieved and/or density be increased ³ Normal concentrations of 0.2% to 2.0% (dry) or 0.02 to 0.5 gals/sk (liquid)

O

Side or Secondary Effects ³ Enhance the action of fluid loss additives ³ Slightly reduce compressive strength ³ Slightly retard the slurry Slide 58

EDC, Tomball, TX

29

CD-32, CD-32L O

Description ³ Modified PNS dispersant

O

Application (Primary Effect on slurry) ³ Used alone to thin cement slurry ³ Used as a building block in FL and BA packages containing BA-10/10A/9L/11 or FL-52

O

Side or Secondary Effects ³ Higher concentration needed as dispersant ³ Reduces FL requirements ³ Less retardation required Slide 59

EDC, Tomball, TX

CD-33, CD-33L O

Description ³ Powdered Or Liquid Dispersant

O

Application (Primary Effect on slurry) ³ Used alone to thin cement slurry

O

Side or Secondary Effects ³ Higher concentration needed as dispersant ³ Improves Fluid Loss Performance of Polymers

Slide 60

EDC, Tomball, TX

30

CD-34L (North Sea) O

Description ³ Liquid biodegradable dispersant

O


O

Side or Secondary Effects ³ Higher concentration needed as dispersant

Slide 61

EDC, Tomball, TX

CD-35L (North Sea) O

Description ³ Liquid biodegradable dispersant

O


O

Newer version of CD-34L

Slide 62

EDC, Tomball, TX

31

CD-Ultra (International) O

Description ³ Liquid dispersant

O


O

Side or Secondary Effects ³ Very effective dispersant and temperature stable ³ International only at this time

Slide 63

EDC, Tomball, TX

CD(+) 500 O

O O O

High temperature dispersant for cement slurries Aids in fluid loss control Can serve as a retarder Primarily Used in OB-1 Spacer System

Slide 64

EDC, Tomball, TX

32

Sodium Gluconate O

Dispersant for Magna Plus Cement

Slide 65

EDC, Tomball, TX

Bonding Additives (Gas Migration Control) O

Primary Purpose ³ To prevent the intrusion of wellbore fluid during the hydration of the cement slurry

O

Secondary Purposes ³ Increase Bonding ³ Minimize Shrinkage ³ Increase Slurry Stability ³ Minimize Free Fluid

Slide 66

EDC, Tomball, TX

33

Gas Migration Possible Causes O O O O O O

Slow Transition Times Bridging Excess Free Fluid Particle Segregation Poor Mud Removal Slurry volume reduction

Slide 67

EDC, Tomball, TX

Gas Migration

HYDROSTATIC PRESSURE

SHALE

PERMEABLE ZONE C A S C I E M E N T

C E M E N T

SHALE

N G

HIGH-PRESSURE ZONE Slide 68

EDC, Tomball, TX

34

Gas Migration PERMEABLE ZONE

HYDROSTATIC PRESSURE

C A S C I E

SHALE

M E N T

C E M E N T

SHALE

N G

FREE FLUID

HIGH-PRESSURE ZONE

Slide 69

EDC, Tomball, TX

Gas Migration HYDROSTATIC PRESSURE

PERMEABLE ZONE CEMENT FILTRATE FLOW

SHALE

C A S I C E M E N T

CEMENT FILTRATE FLOW

N G

C E M E N T

SHALE


EDC, Tomball, TX

35

Gas Migration HYDROSTATIC PRESSURE

PERMEABLE ZONE C A S I


SHALE


SHALE N G FLOW

FLOW


EDC, Tomball, TX

Slide 72

EDC, Tomball, TX

36

Gas Migration Prevention O O O O

Zero Free Fluid Fluid Loss < 50 Cc's Minimize Shrinkage Use Appropriate Mechanism ³ Permeability reduction ³ Film forming ³ Energized slurry and/or expansive system ³ Thixotropic

Slide 73

EDC, Tomball, TX

Bonding Agents (Gas Migration Control) O

Film Forming ³ ³ ³ ³ ³ ³ ³ ³ ³ ³

BA-10 BA-11 BA-9L BA-55 BA-55HT BA-56 BA-56HT BA-86L Flag-56 FL-62

O

Internal Bridging ³ ³ ³ ³ ³ ³ ³

O

BA-58 BA-58L BA-90 BA-100 BA-100LS CSE BA-65

Expansive ³ EC-1, EC-2, ³ BA-61 Slide 74

EDC, Tomball, TX

37

BA-10 and BA-10A O

O

O

O

O O

BJ’s most often used matrix flow control agent to improve cement bonding without affecting early compressive strength development Can be used in lightweight, standard, foamed, or densified slurries Adhesive properties enhance the hydraulic seal between the cement and casing Reduces formation damage and minimizes annular gas migration 80 – 240 °F (25 – 115 °C) 0.2 to 2% BWOC Slide 75

EDC, Tomball, TX

BA-11 O

O

O

O

O O

BJ’s matrix flow control agent to improve cement bonding without affecting early compressive strength development Can be used in lightweight, standard, foamed, or densified slurries Adhesive properties enhance the hydraulic seal between the cement and casing Reduces formation damage and minimizes annular gas migration 180 – 300 °F (82 – 149 °C) 0.2 to 1% BWOC Slide 76

EDC, Tomball, TX

38

BA-9L O

O O O O

Gas migration control and fluid loss additive Provides free water and fluid loss control Stabilizes foamed cements 300 °F (150 °C) 15 - 60 gal/100 sacks, 1.5 to 2% BWOC

Slide 77

EDC, Tomball, TX

BA-56 O O

O O O O O O

Controls gas migration through polymeric means A blend of water-soluble polymers, functional at a wide temperature range Compatible with most cements and additives Superior bond logs Good compressive strength development Predictable performance 240 °F (115 °C) 1 to 2% BWOC

Slide 78

EDC, Tomball, TX

39

Flag-56 (International version of BA-56 Singapore) O O

For fluid loss and gas control 1.0 to 1.5% BWOC

Slide 79

EDC, Tomball, TX

BA-56 HT O O

O O O O O O


Slide 80

EDC, Tomball, TX

40

BA-55 O O

O O O O O O


Slide 81

EDC, Tomball, TX

BA-55 HT O O

O O O O O O


Slide 82

EDC, Tomball, TX

41

BA-58 O O O O O O O

A very fine, gray, free-flowing siliceous powder combined with high molecular weight resins Reduces permeability of the cement while improving the compressive strength Helps suspend solids and prevent free-water separation Fills void spaces between the cement particles and compensates for cement shrinkage Use in dense slurries 15.6 ppg (1870 kg/m3) and above 350 °F (175 °C) 1.5 - 15% BWOC Slide 83

EDC, Tomball, TX

BA-58L (International) O O

Liquid version of BA-58 Use in dense slurries 15.6 ppg (1870 kg/m3) and above

Slide 84

EDC, Tomball, TX

42

BA-59/BA-61 O

O O O

Controls gas migration through the formation of compressible cement - In situ Gas generation Improves bonding and minimizes gas migration through slurry expansion 350 °F (175 °C) 0.2 to 0.8% BWOC (BA-59 - Resin coated Aluminum)

O

1 to 1.5% BWOC (BA-61Charcoal)

O

Do not Batch Mix

Aluminum combined with Active

Slide 85

EDC, Tomball, TX

BA-65 (International) O O O

Expansion additive and extender Increases Bonding Potential 0.5 to 1 ft3 per ft3 of cement

Slide 86

EDC, Tomball, TX

43

BA-86L International O

O

O O

O O O O

A styrene-butadiene, latex cement additive providing excellent fluid loss control, low viscosity, enhanced bonding and acid resistance. Can be used in a wide variety of cement slurries for all primary and remedial cementing applications Can be pumped in turbulent flow at low rates Fills void spaces between the cement particles and compensates for cement shrinkage Use in dense slurries 15.6 ppg (1869 kg/m3) and above 350°F (175°C) 1.0 to 3.0 gals per sack Requires stabilizer (LS-1, LS-2, LS-3) Slide 87

EDC, Tomball, TX

BA-90 O

O

O

O O

An uncompacted silica fume that produces high compressive strengths, lowers cement densities, and prevents annular gas migration by reducing slurry permeability. Suitable for both primary and remedial cementing applications at all temperatures Improves compressive strength of slurries of all densities and assists in reducing hightemperature strength retrogression Improves cement bond logs 10 to 25% BWOC Slide 88

EDC, Tomball, TX

44

BA-100 (International) O O

O

O

Gas migration control additive Improves slurry stability and helps control free water to 400 °F (205 °C) Controls gas migration by reducing permeability during hardening 0.5 to 5% BWOC

Slide 89

EDC, Tomball, TX

BA-100LS (International) O

O

O O

Reduces cement permeability by physical and chemical means Improves compressive strength and controls free water Liquid suspension of fine particles 0.5 to 3.0 gal/sack

Slide 90

EDC, Tomball, TX

45

CSE O

O

O

O

Improves cement bonding and early compressive strength development Free flowing siliceous fume for use at all temperatures For use in low density slurries, 15.6 ppg (1870 kg/m3) and below 8 to 25% BWOC

Slide 91

EDC, Tomball, TX

CSE-2 Permian Basin O

O

O

O

Improves cement bonding and early compressive strength development Free flowing crystalline silica for use at all temperatures For use in low density slurries, 15.6 ppg (1870 kg/m3) and below 5 to 20% BWOC

Slide 92

EDC, Tomball, TX

46

Free Water Control O O O O O O

Sodium Metasilicate Atapulgite Clay T-40L ASA-301 and ASA-301L ASA-500 Purpose: ³ Eliminate free water in cement slurries

Slide 93

EDC, Tomball, TX

A-2, Sodium Metasilicate O

Description ³ Very light white powder

O

Application (Primary Effect on slurry) ³ Eliminates free water in cement slurries ³ Normal concentrations 0.15 to 0.8% BWOC

O

Side or Secondary Effects ³ Slight acceleration effect ³ Difficult to retard above 100 °F (38 °C)

Slide 94

EDC, Tomball, TX

47

Attapulgite Clay O

Cement extender & free water control agent ³ Rarely used, but more effective in salt slurries than bentonite ³ Caution needs to be observed when using this clay - Can lead the cement to Flash Set

Slide 95

EDC, Tomball, TX

T-40L (International) O

Description ³ Liquid Inorganic Salt, that increases slurry viscosity to minimize free water development ³ Improves Early Compressive Strength Development

Slide 96

EDC, Tomball, TX

48

ASA-301 & ASA-301L O

O

O

Free water and anti-settling agent control agent for cement Temperatures between 80 and 300 °F (27 °C and149 °C) (BHCT) Normally used at concentrations between 0.05 - 0.2% (BWOC) (or 1.0 - 4.0 ghs)

Slide 97

EDC, Tomball, TX

ASA-500 O

O O

High Temperature free water and antisettling agent control agent for cement Temperatures above 250°F (BHCT) Normally used at concentrations between 0.5 - 1.5% (BWOC)

Slide 98

EDC, Tomball, TX

49

Sepiolite Canada O O O

Free water control agent and extender Salt water compatible extender Similar to attapulgite clay

Slide 99

EDC, Tomball, TX

Microsil 12P Canada O O

O

Compacted silica fume Very fine amorphous silica source absorbs free fluid Improves performance of fluid loss agents in slurry

Slide 100

EDC, Tomball, TX

50

Extenders O

Principal generic types ³ Clays Ë Bentonite

³ Chemical extenders Ë A-2, A-3L, A-300L

³ Low density inert solids Ë Kolite, LCM-1

³ Low density reactive solids Ë Pozzolans (Fly Ash , Perlite, etc)

Slide 101

EDC, Tomball, TX

Extenders O

Principal generic types (cont.) ³ Gases Ë Nitrogen, Air (Foamed Cement)

³ Microspheres Ë LW-6 (Lite-set), 3M Glass Spheres (LW-7) O

Primary use ³ Reduce the hydrostatic head of the cement column

O

Purpose ³ Increase yield ³ Decrease density ³ Better economics Slide 102

EDC, Tomball, TX

51

Bentonite (Gel) O

Description ³ Wyoming Bentonite ³ Thixotropic, high water requirement

O

Application (Primary Effect on slurry) ³ Allows addition of more water in a slurry, giving a higher yield and lower density, while maintaining slurry integrity. Limits settling or free water. ³ Usually lowers cost per cuft of yield

Slide 103

EDC, Tomball, TX

Bentonite (Gel) (cont.) O

Side or Secondary Effects ³ Ties up free water ³ Helps control filtrate (fluid) loss ³ Slightly accelerates ³ Lowers compressive strengths

O

Special Notes ³ Normal usage 2% - 8% ³ High percentages 10 - 16%, thick and hard to pump ³ 1% pre-hydrated in fresh water = 4% dry ³ 1% pre-hydrated in sea water = 3% dry Slide 104

EDC, Tomball, TX

52

Fly Ash (Poz) O

Description ³ Ash from combustion of coal, ³ By-product of coal-fired power plants ³ Used as synthetic pozzolan (Poz)

O

Application (Primary Effect on slurry) ³ Allows addition of more water in a slurry, giving a higher yield and lower density, while maintaining slurry integrity ³ Usually lowers cost per cubic foot of yield

Slide 105

EDC, Tomball, TX

Fly Ash (cont.) O

Side or Secondary Effects ³ Lowers compressive strengths ³ Some resistance to sulfate attack ³ Some resistance to strength retrogression

O

Special Notes ³ Normal percentages: 15 to 50 ³ No temperature limitations ³ Usually used with small percentage of gel to tie up free water Slide 106

EDC, Tomball, TX

53

LW-6 O

Description ³ Light gray Ceramic spheres ³ Can create a slurry density as low as 8.5 ppg (1020 kg/m3)

O

Application (Primary Effect on slurry) ³ Retains good compressive strengths ³ Normal concentrations 5 to 60%

O

Side or Secondary Effects ³ Wear protective masks when loading

O

Special Notes ³ Up to 20% of product crushes at 2,000 psi (13.8 Mpa) Slide 107

EDC, Tomball, TX

LW-7 O

Description ³ Borosilicate glass microspheres (S.G. 0.3 to 0.7) ³ Can create a slurry density as low as 8.0 ppg (960 kg/m3)

O

Application (Primary Effect on slurry) ³ Retains good compressive strengths ³ Normal concentrations 5 to 60%

O

Side or Secondary Effects ³ Wear protective respirator and goggles when loading

O

Special Notes ³ Comes in a multiple crush (20%) ratings, 1K to 18K psi (6.9 MPa to 124.2 MPa) ³ Crush designated by last # i.e. LW-7-4 > 4000 psi (27.6 MPa)crush

Slide 108

EDC, Tomball, TX

54

Perlite O O O

O

An expanded, volcanic material Effective in bridging off fractures Will crush under pressure (i.e., care must be taken to determine what the slurry density will be under down hole conditions) Other common product names, Perf-A-Lite and Perfolite

Slide 109

EDC, Tomball, TX

O

A-2, Sodium Metasilicate (EXC, Canada) and A-3L, Sodium Silicate (Liquid) (EXC-L, Canada) Description ³ white powder (A-2) or viscous clear/white liquid (A-3L) ³ also known as SMS (A-2) or SSL (A-3L)

O

Application (Primary Effect on slurry) ³ Allows addition of more water in a slurry, giving a higher yield and lower density, while maintaining slurry integrity. Usually lowers cost per cubic foot of yield. ³ Excellent extender Slide 110

EDC, Tomball, TX

55

O

A-2, Sodium Metasilicate (EXC, Canada) and A-3L, Sodium Silicate (Liquid) (EXC-L, Canada) (cont.) Side or Secondary Effects ³ lowers compressive strengths somewhat ³ provides some thixotropic properties ³ mild accelerator ³ excellent free water control

O

Special Notes ³ normal percentages: 1, 2, 3 or 4 (dry) BWOC (A-2) ³ temperature limitation of 150 °F (65 °C) Slide 111

EDC, Tomball, TX

Lost Circulation Types O

Bridging materials ³ Granular ³ Flake ³ Fiber ³ Blends

O O O

Thixotropic cement Polymeric blends Inorganic cement

Slide 112

EDC, Tomball, TX

56

Lost Circulation Materials (LCM) O

Granules (ground-up) ³ LCM-1: (gilsonite) ³ Kol Seal: (coal) ³ Nut Plug: (walnut shells) ³ Perfect Seal: (bricks) ³ Mud-Save F (Batteries) ³ Mud-Save M (Batteries) ³ Flex Seal: (rubber) ³ Max Seal: (¼” rubber)

O

Flakes ³ Cello Flake Ë cellophane flakes

O

Fibers ³ BJ Fibers

O

Blends ³ Kwik Seal

O

Specialty ³ PolyFX ³ Cuttings-K

Slide 113

EDC, Tomball, TX

Cello Flake O

O O O

Shredded cellophane film sized to 3/8” for lost circulation agent for cement slurries Chemically inert Low density Normal concentration 1/8 - 1/2 #/sk

Slide 114

EDC, Tomball, TX

57

LCM-1 O O O

O O

O

Solid granular hydrocarbon Specific Gravity 1.07 Effective up to 300 °F (150 °C) depending on type Chemically inert Impermeable and soft enough to permit pressure deformation for improved sealing Normal Concentration 1 - 25 #/sk Slide 115

EDC, Tomball, TX

Kol Seal O O

O

O

Ground coal lost circulation agent Specific particle size distribution for maximum bridging efficiency Lowers slurry weight and reduces hydrostatic pressure Normal concentration 2 - 25 #/sk

Slide 116

EDC, Tomball, TX

58

Nut Plug O

O

Ground up sized walnut hulls used as a bridging agent More commonly used in mud than in cement

Slide 117

EDC, Tomball, TX

BJ Fiber O

O

Helps increase durability and resistance to mechanical shock Prevents cracking and crumbling ³ Helpful when milling windows in casing

O O O

O

Reduces lost circulation Normal concentration 0.1 - 1% BWOC Should be added at the mixing tub - can bridge across the knifegate Do Not Dry Blend Slide 118

EDC, Tomball, TX

59

Max Seal O O

O

Ground tires lost circulation agent Softness allows pressure deformation for improved sealing Used in concentrations of 1 - 5 #/sk

Slide 119

EDC, Tomball, TX

Mud Save F and M O O

O

O

Ground Thermoset plastic material Inert, not reactive with muds or formation fluids Fine Material “F” for smaller fractures and high perm loss zones Medium materials for larger fractured loss zones Not currently available from supplier

Slide 120

EDC, Tomball, TX

60

Kwik Seal O O O

O O

Lost circulation agent for mud and cement Mixture of flakes, granules, and fibers Can be used in cement in concentrations of 1/4 - 1.0 #/sk Fibrous material derived from sugar cane Commonly used in mixing mud LCM pills ³ Used at concentrations from 5 - 80 #/bbl

Slide 121

EDC, Tomball, TX

PolyFX O

O O O

Crosslinked polymer suspension used for temporary sealing of lost circulation zones 100% Acid removable Reactive with any downhole water source Applicable @ temps to 300 °F (150 °C)

Slide 122

EDC, Tomball, TX

61

Cuttings-K O O O O

Acid soluble LCM Soluble in 15% Acid Used with Magneplus or as a LCM pill Concentrations of 35 - 70 #/bbl are used in pills

Slide 123

EDC, Tomball, TX

Specialty LCM O

FlowGuard ³ Liquid permanent loss circulation agent for non-productive thief zones

O

Gunk Squeeze (DOB or DOB2C) ³ Gel-Diesel-mix ³ when contaminated with water based fluid, forms a viscous mass ³ DOB2C is same as above with 2 sks cement added/bbl of material

Slide 124

EDC, Tomball, TX

62

Flow Guard O O

O

O

O

Sodium Silicate and water (50:50) Plugs formation permeability permanently by forming white colloidal precipitates when contacted by fluid containing calcium or magnesium Used to plug off lost circulation zones while drilling in non-productive interval Used to create a barrier in very porous zones so that squeeze jobs may be obtained Also used in diluted form as a pre-flush on production casing cementing jobs Slide 125

EDC, Tomball, TX

Gunk Squeeze O

O

When contaminated with mud, forms sticky putty-like materials Gel-Diesel-mix ³ Additives for 10 bbls of 11.2 ppg Ë 7 bbls Diesel Ë 27 sacks Bentonite

O

Usage ³ Lost Circulation Zones ³ Normally placed between stages of diesel Slide 126

EDC, Tomball, TX

63

Poly Fibre 50 Canada O O O

O

Polypropylene fibres Fibres provide bridging action provides stress strength control to the set cement resistance to shattering and cracking of cement

Slide 127

EDC, Tomball, TX

Thixseal Flush P Canada O O

O

Powder Silicate and water based system. Pumped as a clear low viscosity preflush solution. Creates gel upon contact with cations present in formation fluids in well bore annulus.

Slide 128

EDC, Tomball, TX

64

Weighting Material O

Desirable Criteria ³ Compatible particle size ³ Low water requirement ³ Inert ³ Cost effective

O

Purpose ³ Increase the density of the slurry

Slide 129

EDC, Tomball, TX

Weighting Materials O O O O

Barite Hematite W-10 Sand

Slide 130

EDC, Tomball, TX

65

Barite O

Description ³ Barium sulfate, BaSO4 ³ Also known as “bar” - - material used in drilling muds ³ Light tan to reddish/pink colored powdered material

O

Application (Primary Effect on slurry) ³ Increases slurry density from 16.8 to 22+ ppg (2010 to 2600+ kg/m3)

Slide 131

EDC, Tomball, TX

Barite (cont.) O

Side or Secondary Effects ³ Particle size not consistent - - difficult to mix ³ Impurities not compatible with other cement additives ³ Requires more mixing water ³ Settling

O

Special Notes ³ Seldom used to weight cement slurries (any longer)

Slide 132

EDC, Tomball, TX

66

Hematite O

Description ³ Hematite = Iron Oxide = Fe2O3 = ferric oxide = rust ³ Dry, fine-grained, red mineral ³ Specific gravity = 5.02

O

Application (Primary Effect on slurry) ³ Increases slurry density from 16.8 to 22+ ppg (210 to 2600+ kg/m3) ³ Usually 5 to 100% BWOC, also expressed in lb/sack Slide 133

EDC, Tomball, TX

W-10 O

Description ³ Manganese Tetraoxide, Mn3O4

O

Application (Primary Effect on slurry) ³ Increases slurry density from 16.8 to 22+ ppg (2010 to 2600+ kg/m3) ³ Can be added to mixing water, prior to mixing cement

O

Secondary Effects ³ No settling, very effective ³ More expensive than hematite, not readily available in USA

O

Special Notes ³ Releases free chlorine gas (Cl2Ç) on contact with hydrochloric acid (HCl) ³ Developed in Europe for North Sea market

Slide 134

EDC, Tomball, TX

67

Sand O

Description ³ Frac sand, or just sand ³ Chemically is Silicon Dioxide (SiO2)

O

Application (Primary Effect on slurry) ³ Increases slurry density from 16.8 to 18.5 ppg (2010 to 2220 kg/m3) ³ without a dispersant

Slide 135

EDC, Tomball, TX

Sand (cont.) O

Side or Secondary Effects ³ In sufficient quantities, can prevent strength retrogression ³ Requires more mixing water ³ Settling

O

Special Notes ³ Does not make cement harder ³ S.G. is less than cement (2.63 for sand vs. 3.14 for cement), but greater than water

Slide 136

EDC, Tomball, TX

68

Miscellaneous O

Harborlite 2000 ³ Very fine form of Perlite, international only

O

KCl Free ³ Non-KCl clay control for cements or spacers

Slide 137

EDC, Tomball, TX

Multi-Purpose Additives O O O O O O O

A-10, Gypsum A-11, Lime BJ Ultra EC-1/EC-2 MPA-1 MPA-3 A-300L-International Static Free

O

Canada ³ Quick-Gyp ³ Gypcem 120 ³ Microsil 12P ³ SPC-12000

Slide 138

EDC, Tomball, TX

69

BJ Ultra International O

O

O O O O

Cost effective Sodium Silicate based Multipurpose Additive Combines fluid loss, free water and gas migration control Excellent in low to moderate density slurries Temperatures from 80 to 300 °F (27 to 149 °C) Concentrations range from 0.2 to 1.5 gps Allows for a reduction of # of additives used

Slide 139

EDC, Tomball, TX

A-10, A-10B O

Gypsums can be used as cement additives or by themselves as a cementatious materials ³ A-10 and A-10B differ in hydration state and reactivity Ë A-10 is a mixture of calcium sulfate hemihydrate (Plaster of Paris) and Portland cement (less than 5%)

O

O O

Used primarily as an additive to impart thixotropic slurry properties in special lightweight systems Accelerates compressive strength development Use with great caution over 140 °F (60 °C)

Slide 140

EDC, Tomball, TX

70

A-11, Hydrated Lime O

O

O

Very effective, early compressive strength enhancer for cement Provides rapid acceleration and must be used with caution Generally used only in low-temperature applications

Slide 141

EDC, Tomball, TX

AEF-100L (International) O

Description ³ Is a Multifunction Liquid Additive Used to Accelerate, Extend and Control Free Fluid in Cement Slurries.

O

Application (Primary Effect on Slurry) ³ Shorten Thickening Time ³ Increase Early Compressive Strength Development

O

Special Notes ³ Normal Usage 5 to 20 gps Slide 142

EDC, Tomball, TX

71

T-40L (International) O

Description ³ Liquid Inorganic Salt, That Provides Thixotropic Properties to Low Density Cement Slurries

O

Application (Primary Effect on Slurry) ³ Thixotropic Additive for Slurry Densities from 12.5 to 14.5 ppg (1497 to 1737 kg/m3) ³ Normal Usage as Thixotropic Additive 25 to 60 gps ³ Accelerates Slurries at 5 to 15 gps Depending Upon Temp. And Density ³ Helps Control Free Fluid ³ Improves Early Compressive Strength Development

Slide 143

EDC, Tomball, TX

EC-1/EC-2 O

O O O O O O

Expands the set cement to compensate for shrinkage, resulting in a better bond of pipe and formation to the cement Accelerates thickening time Helps inhibit gas migration Reduces WOC time Degree of expansion can be controlled by modifying additive concentration EC-1 - < 200 °F (93 °C) EC-2 - > 200 °F (93 °C) Slide 144

EDC, Tomball, TX

72

MPA-1 O

O

Fine white pozzolanic powders used to enhance various cement properties Functional at temperatures of 32 °F (0 °C) to over 400 °F (204 °C) (International) ³ Not recommended > 180 °F (82 °C) in North American

O

O

Enhanced compressive strength development and reduced permeability Concentrations range from 1 to 30% BWOC (dry) or equivalent liquid

Slide 145

EDC, Tomball, TX

MPA-3 O

Used to enhance mechanical cement properties ³ ³ ³ ³

O

O O

O

Increase Tensile Strength Improve compressive to tensile strength ratio Lowers Young’s Modulus Increase Poisson’s Ratio

Functional at temperatures of 32 °F (0 °C) to over 400 °F (204 °C) Improves Sulfate resistance Reduces permeability during hydration of the cement matrix Concentrations range from 12 to 100% BWOC Slide 146

EDC, Tomball, TX

73

Static Free O

Anti-static additive for proppants and dry cement ³ Especially useful for microsilica containing systems ³ Aids in the unloading of certain frac proppants

Slide 147

EDC, Tomball, TX

Quick-Gyp Canada O O

O

Economic form of gypsum Used in thixotropic cements (Thix-Mix NP and G, BVC-30 Provides post set expansion in cement

Slide 148

EDC, Tomball, TX

74

Gypcem 120 Canada O O

O

Processed form of gypsum Used in Polarset for cementing across permafrost Used in Rapidset cement

Slide 149

EDC, Tomball, TX

Microsil 12P Canada O O

O O

Compacted silica fume Used over uncompacted silica fume to allow for pneumatic handling and regular handling Controls free fluid control in cement Improves cement matrix impermeability

Slide 150

EDC, Tomball, TX

75

SPC-12000 Canada O

O

O

Aluminium powder which generates hydrogen gas in cement slurry Provides positive pressure against formation pressure Accelerates thickening time

Slide 151

EDC, Tomball, TX

Strength Retrogression O

Term used to describe the break-down of cement's compressive strength and an increase in permeability when the cement is exposed to excessive temperatures, typically > 230 °F (110 °C)

Slide 152

EDC, Tomball, TX

76

Strength Retrogression Prevention O

Prevention of strength retrogression is done simply by adding fine silica (less than 200 mesh) ³ Coarse silica may also be used, but due to slower reactivity may exhibit different strength/time profile

O

O

It was previously thought that 35% by weight of cement was the minimum and pretty much the standard New information indicates optimum loading may be from 35 to 40 % BWOC, but higher concentrations may be required in special cases

Slide 153

EDC, Tomball, TX

Strength Retrogression Materials O O O O

Silica Flour, S-8 (Canada SFA-325) Course Silica, S-8C Sand SL-1 Silica Fume (BA-58 or BA-90) may be substituted for a portion of the other silica

Slide 154

EDC, Tomball, TX

77

Silica Flour, S-8 (Canada SFA-325) O

Description ³ Less than 200 mesh silica flour

O

Application (Primary Effect on slurry) ³ Optimal concentration 35 to 40% BWOC Ë Base cement and well condition dependant

³ In proper amounts, can prevent strength retrogression ³ Generally used for slurries up to 16.8 ppg (2010 kg/m3) Ë For heavier slurries, 100 mesh or blend of two is used to keep viscosity lower Slide 155

EDC, Tomball, TX

Coarse Silica, S-8C O

Description ³ 80 to 140 mesh (average 100) silica sand

O

Application (Primary Effect on slurry) ³ Optimal concentration 35-40% BWOC ³ In proper amounts, can prevent strength retrogression ³ Generally used for slurries above 16.8 ppg (2010 kg/m3)

Slide 156

EDC, Tomball, TX

78

Sand O

Sand, or frac sand, is not used in cement slurries to prevent strength retrogression ³ Although they are all chemically the same silicon dioxide (SiO2), sand reactivity is much lower/slower due to much lower surface area.

Slide 157

EDC, Tomball, TX

SL-1 O

Description ³ Liquid suspension of SiO2

O

Application (Primary Effect on slurry) ³ Optimal loading 3.0 gal/sk (equals +/- 35% BWOC) ³ In proper amounts, can prevent strength retrogression

O

Secondary effect - slurry viscosity increase Slide 158

EDC, Tomball, TX

79

Foaming Agent

O

FA-12S FAW-20 FAW-21G

O

Purpose:

O O

³ Produce a low density, stable foamed cement with the induction of nitrogen gas

Slide 159

EDC, Tomball, TX

Foam Preventers O

Purpose ³ To control or eliminate entrapped air in the cement slurry, which can cause mixing problems

O

Types ³ Polyglycol ethers ³ Tributyl phosphate ³ Silicones ³ Diesel

Slide 160

EDC, Tomball, TX

80

Foam Preventers O O O O O O

FP-6L FP-9L, FP-9LS FP-11 FP-12L, FP-12S FP-13L FP-16LG

Slide 161

EDC, Tomball, TX

FP-6L O

Description ³ Long chain alcohols and glycols

O

Application (Primary Effect on slurry) ³ Prevents or disperses surface foam ³ Theoretical concentration: 1 quart per 10 barrels of mixing water

O

Side or Secondary Effects ³ None significant

Slide 162

EDC, Tomball, TX

81

FP-9L International O

Liquid cement defoamer

Slide 163

EDC, Tomball, TX

FP-9LS International O

Liquid cement defoamer

Slide 164

EDC, Tomball, TX

82

FP-11 O O O

O

O

O

Powdered de-foamer for cement slurries Dry-blended into cement slurry Can be used in a broad range of slurry designs and density ranges Prevents excessive entrained air in the slurry, providing better density control Does not affect thickening time or compressive strength development 0.1 to 0.4 % BWOC Slide 165

EDC, Tomball, TX

FP-12L O O O

Silicon oil emulsion 0.001 to 0.02 gal/sack Effective to 500 °F (260 °C)

Slide 166

EDC, Tomball, TX

83

FP-12S International O O

Silicon oil emulsion 0.001 to 0.02 gal/sack

Slide 167

EDC, Tomball, TX

FP-13L O

O

Liquid, water dispersible cement defoamer 0.5 to 2 gal/100 sacks

Slide 168

EDC, Tomball, TX

84

FP-16LG International O O

Europe cement anti-foamer Environmentally friendly

Slide 169

EDC, Tomball, TX

85

Cementing Products Section 8 Part C - Spacers June 2006

Printed: 6/12/2006

EDC, Tomball, TX




Slide 2

EDC, Tomball, TX

1

Spacers And Washes O

These fluids are used to: ³ Increase mud displacement efficiency ³ Clean mud from the casing and formation ³ Water wet the casing and formation ³ Separate mud from cement inside pipe and in the annulus ³ Minimize contamination

Slide 3

EDC, Tomball, TX

Spacers And Washes O

Spacers ³ Weighted fluids used to maintain hydrostatic pressure for well control ³ Can be used in laminar (plug) or turbulent flow ³ Have buoyancy effect on mud removal

O

Washes (or flushes) ³ Not weighted ³ Easy to mix and pump ³ Turbulence achieved at very low rates, even in large hole/casing configurations Slide 4

EDC, Tomball, TX

2

Effect of Mud and Mud Additives on Cement O

Barite

O

³ Increase density, reduce strength O

Caustics

³ Retard set (leakage to formation) O

³ Accelerate set O

Calcium compounds Hydrocarbons ³ Decrease density, retard set

O

Thinners ³ Retard set

O

³ Accelerate set O

Sealants

Emulsifiers ³ Retard set

O

Bactericides ³ Retard set

O

Fluid loss additives

Whole mud ³ Can form unpumpable mass

³ Retard set

Slide 5

EDC, Tomball, TX

Effect of Mud Additives on Cement

Slide 6

EDC, Tomball, TX

3

Wash/Spacer Design O

Spacers must be compatible with other fluids ³ Oil-based or Water-based Mud ³ Testing Ë Compatibility Testing Ë Mud Removal Testing Ë Wettability Testing

O

Formation compatibility ³ Shales, Salt Zones

O

Spacer density should be between mud and cement ³ Normally 0.5 ppg over mud weight

O

Volumes based on flow regime ³ Turbulent (Best) - 10 minutes contact time ³ Laminar - 500 ft [152.4 m] annular fill

Slide 7

EDC, Tomball, TX

Additives Used in Spacers and Washes O

Surfactants ³ Water wet pipe and formation - better bonding

O

Weighting materials ³ Well control, improve mud displacement buoyancy effect

O

Thinning agents ³ Thin mud, reduce viscosity ³ Break up mud cake

Slide 8

EDC, Tomball, TX

4

Additives Used in Spacers and Washes (cont.) O

Gelling agents ³ Solids suspension ³ Fluid stability

O

Flocculants ³ Help in removal of clay based muds

O

Scouring and Cleaning Agents ³ Remove mud cake from pipe and formation

Slide 9

EDC, Tomball, TX

Additives Used in Spacers and Washes (cont.) O

Plug flow agents ³ Form viscous mass at interface between mud and spacer to achieve sweeping action (Plug flow only)

O

Salts ³ Sensitive shales ³ Massive salts

O

Corrosion inhibitors ³ Prevent corrosion where spacer is left behind casing Slide 10

EDC, Tomball, TX

5

Flushes, Washes and Spacers O

Your class binder includes a copy of a brochure on flushes, washes and spacers

Slide 11

EDC, Tomball, TX

Spacers & Flushes Non-Weighted O O

Mud Clean I Mud Clean II

Slide 12

EDC, Tomball, TX

6

Mud Clean I O

A water-based, non-acid solution used as a preflush between the drilling mud and cement ³ Contains surfactant

O

O

O

O

Most common preflush on casing jobs to remove drilling fluid and filter cake from the wellbore Non-corrosive can be used when the preflush will not be circulated out of the well Promotes excellent mud removal by thinning the mud and loosening the filter cake Water-wetting properties enhance bonding Slide 13

EDC, Tomball, TX

Mud Clean II O

O

O

O

O

A water-based, non-acid solution used as a preflush between the drilling mud and cement. Most common preflush on casing jobs to remove drilling fluid and filter cake from the wellbore. Non-corrosive can be used when the preflush will not be circulated out of the well Promotes excellent mud removal by thinning the mud and loosening the filter cake Water-wetting properties enhance bonding

Slide 14

EDC, Tomball, TX

7

Spacers & Flushes Weighted O O O O O O

MCS-2 MCS-3 MCS-4 MCS-5 MCS-O MCS-W

O O O O

OB-1 RSB Spacer Surebond I, II & III Ultra Flush II

Slide 15

EDC, Tomball, TX

MCS-2 O

O

O

A turbulent-flow spacer system that prevents water-based mud contamination while water-wetting the casing to increase bonding. Compatible with cement and water-based drilling mud Good fluid loss control properties

Slide 16

EDC, Tomball, TX

8

MCS-2 (cont.) O

O

O

Rig products can be used for gelling and weighting Adjustable viscosity and density for required hydrostatics and flow regime Wide temperature application

Slide 17

EDC, Tomball, TX

MCS-3 O

O

O

A turbulent-flow spacer system that prevents oil-base mud contamination while water-wetting the casing to increase bonding. Compatible with cement and oil-based drilling mud. Prevents cement flash-setting that could result from oil-mud contamination

Slide 18

EDC, Tomball, TX

9

MCS-3 (cont.) O O

O

Good fluid loss control properties Adjustable viscosity and density for required hydrostatics and flow regime Wide temperature application

Slide 19

EDC, Tomball, TX

MCS-4 O

O

A turbulent-flow spacer system that prevents water and oil-based mud contamination while water-wetting the casing to increase bonding. Can be mixed “on-the-fly” with a jet or recirculating mixer (i.e. dry-blended spacer)

Slide 20

EDC, Tomball, TX

10

MCS-4 (cont.) O O

O


Slide 21

EDC, Tomball, TX

MCS-5 International O

O

O


Slide 22

EDC, Tomball, TX

11

MCS-5 (cont.) International O O

O O

Good fluid loss control properties Adjustable viscosity and density for required hydrostatics and flow regime Wide temperature application Use caution when mixing as system may foam

Slide 23

EDC, Tomball, TX

MCS-W South America O

O

O

A turbulent-flow spacer system that prevents water-based mud contamination while water-wetting the casing to increase bonding. Compatible with cement and water-based drilling mud Good fluid loss control properties

Slide 24

EDC, Tomball, TX

12

MCS-W South America (cont.) O

O

O

Rig products can be used for gelling and weighting Adjustable viscosity and density for required hydrostatics and flow regime Wide temperature application

Slide 25

EDC, Tomball, TX

MCS-O South America O

O

O


Slide 26

EDC, Tomball, TX

13

MCS-O South America (cont.) O O

O


Slide 27

EDC, Tomball, TX

OB-1 O

O

O O

Oil-external, emulsion spacer for hematite weighted, oil-external mud systems Compatible with salt saturated cement systems Stable emulsion Should be followed by water wetting spacer

Slide 28

EDC, Tomball, TX

14

RSB Spacer O O

Oil Mud Spacer Made with approximately equal amounts of oil from mud system and water, which enables it to be compatible with oil based mud ³ The exact ratio depends upon individual well requirements.

O

An oil in water emulsion

Slide 29

EDC, Tomball, TX

Surebond I, II & III Blend of Sodium Silicate and Water O Ratios 10:90, 20:80 and 30:70 O Used as a Preflush to Minimize Losses and Promote Bonding O Can Damage the Production Interval if Losses Occur Across Pay Zone Must be separated from cement slurry or Calcium containing fluids by fresh water flush! O

Slide 30

EDC, Tomball, TX

15

Ultra Flush II O

O

Water-based spacer designed to effectively remove drilling mud and wall cake during cementing to prevent contamination of the cement slurry and improve bonding Uses a liquid concentrate mixed in a base water (concentrate does not contain weighting material)

Slide 31

EDC, Tomball, TX

Ultra Flush II (cont.) O O

O O O

Barite, is added for weighting purposes and the spacer is pumped down-hole Can be mixed at 12 to 20 ppg (1438 to 2397 kg/m3) & pumped in turbulent flow (depending upon wellbore) Recommended to 350 °F (177 °C) BHCT Improved wettability Improved flexibility ³ Can be modified with surfactant(s) for use with oil-based muds Slide 32

EDC, Tomball, TX

16

Supersweep Canada O

O

O

O

Water based spacer to prevent contamination of drilling mud with cement slurry Can be densified with calcium carbonate, barite, or hematite Contains surfactants to improve wettability Tested up to 130 °C (266 °F)

Slide 33

EDC, Tomball, TX

HC Sweep Canada O O

O

Oil base viscous spacer Can be densified up to 1,700 kg/m³ (14.2 ppg) with barite Prevents contamination of oil based muds with water based fluids

Slide 34

EDC, Tomball, TX

17

Nowflush 12 Canada O O

Surfactant and water based preflush Uses Nowflush12C surfactant concentrate at 1 to 2 percent

Slide 35

EDC, Tomball, TX

References O

PowerCenter - Technology Tool Box Ë Cementing - Products

Slide 36

EDC, Tomball, TX

18

References O O O O O O O O

BJ Mixing Manual BJ Cementing Engineering Support Manual International MSDS PowerCenter - Cement Products API Recommended Practices 10, 10A and 10B Cement Product Bulletins & Brochures CMFacts Application Engineering Handbook

PRODUCT INFORMATION

Slide 37

EDC, Tomball, TX

19

PRODUCT APPLICATIONS MANUAL Prepared by Technology Support Group Tomball Employee Development Center Tomball, Texas

SECTION ONE Product quick reference sorted by product name, with brief descriptions.

SECTION TWO Detailed product description (3 lines) and application information (2 lines), sorted by product application. (Confidential)

Product Applications Manual 10/17/2005

Section 0 Page 1 of 1

PRODUCT QUICK REFERENCE PRODUCT NAME

APPLICATION

DESCRIPTION

A-10, Gypsum

Special Additive

Enhances early compressive strength development in cement

A-10B, Gypsum, W120

Special Additive

Enhances early compressive strength development in cement

A-11,Lime

Special Additive

Early compressive strength enhancer for cement

A-11A, Hydrated Lime

Special Additive

Early compressive strength enhancer for cement

Acetic Acid/Glacial

Acid - Organic

Glacial acetic acid low pH buffering agent, also used as acetic acid to 20%

Acetic Anhydride Blend

Acid - Organic

Acetic acid /acetic anhydride mixture buffering agent, also used as acetic acid to 20%

Acigel

Gellant - Acid

Polymeric acid gellant and friction reducer

Activator Borden

Resin Activator

Curable resin activator for resin coated proppants at low BHST in water base fluids

Activator Oil, Borden

Resin Activator

Curable resin activator for resin coated proppants at low BHST in oil base fluids

Activator Superset-O

Resin Activator

Curable resin activator for resin coated proppants at low BHST in oil base fluids

Activator Superset-P

Resin Activator

Curable resin activator for resin coated proppants at below 100°Fin water base fluids

Activator Superset-W

Resin Activator

Curable resin activator for resin coated proppants at low BHST in water base fluids

Adomite Regain

Fluid Loss - Stim

Degradable starch fluid loss additive--100% soluble

AG-12

Gellant - Acid

Acid gelling agent, can be used at high-temperatures for hydrochloric acid

AG-21R

Gellant - Acid

HEC (Hydroxyethyl Cellulose) gelling agent, HEC-10

AG-26

Gellant - Acid

Drilling grade xanthan, hydrates rapidly

AG-57L

Gellant - Acid

Acid gelling agent for XL Acid III system

AG-58L

Gellant - Acid

Acid gelling agent for Deep Spot Acid & Deep Spot Delayed Acid system

Ammonium Bifluoride

Miscellanous

Ammonium bifluoride intensifier for HCl / HF acid systems

Ammonium Chloride

Salt

Ammonium Chloride Salt

Ammonium Fluoride

Miscellanous

Ammonium fluoride intensifier for HCl / HF acid systems

Ammonium Hydroxide,30%

pH Control Additive

30%, Ammonium hydroxide solution (26 Be)

Aquacon™ Concentrate

Water Control

Permeability modifier to control water production

AquaCon™ HP

Water Control

Permeability modifier to control water production

AS-66

Anti-Sludge

Acid Anti-Sludge Agent and water wetter, non-emulsifier

ASA-301

Special Additive

Free water and anti-settling agent control agent for cement

ASA-301L

Special Additive

Free water and anti-settling agent control agent for cement

Attapulgite Clay

CMT Extender

Cement extender and aid for control free fluid

BA-10

Bonding

Gas migration control additive, stabilizes foamed cements

BA-10A

Bonding

Gas migration control additive, stabilizes foamed cements

BA-11

Bonding

Used to control gas migration and as a fluid loss additive

BA-56

Bonding

Controls gas migration through polymeric means

BA-56HT

Bonding

Prevents gas migration, controls fluid loss and free fluid through polymeric means

BA-58

Bonding

Improves cement bonding and compressive strength

BA-58L

Bonding

Improves Bonding and compressive strength

BA-59

Bonding


BA-61

Bonding

Controls gas migration through the formation of compressible cement

BA-90

Bonding


BA-9L

Bonding

Liquid suspension for BA-10 used to control gas migration and as a




APPLICATION

DESCRIPTION fluid loss additive

Barite

Weighting Materials

weighting agent for spacers

BC-3

Breaker Catalyst

Used to bring down pH of system. Can be used with all breakers.

BC-31

Breaker Catalyst

Low temperature liquid catalyst for oxidizing breakers

BC-5

Breaker Catalyst

Used to bring down pH of system. Can be used with all breakers.

BC-6

Breaker Catalyst

Catalyst for oxidative breakers at temperatures below 120°F.

BD-Buff 54

CF - Fluid Loss

Alkaline buffer designed for pH control and maintenance in brinebased drill-in fluids

BD-FL 44

CF - Fluid Loss

Starch based crosslinked polymer specially designed for fluid loss control in brine-

BD-Vis 129

CF - Viscosifier

High purity biopolymer specially designed for hole cleaning and solids suspension in

BD-Vis 130

CF - Viscosifier

High purity biopolymer specially designed for hole cleaning and solids suspension in

Bentonite

CMT Extender

Economical cement extender

Benzoic Acid

Blocking Agent

Temporary diverting agent in either producing or injection wells

BF-12L

pH Control Additive

Vistar low pH buffer or Medallion LpH

BF-15L

pH Control Additive

High pH Buffer, adjust fracturing gels into the range of 10.5 to 12.5

BF-16L

pH Control Additive

High pH Buffer, adjust fracturing gels into the range of 10.5 to 12.5

BF-7L

pH Control Additive

Liquid high pH buffer

BF-8L

pH Control Additive

High pH buffer for use in sea-water systems

BF-9L

pH Control Additive

High pH buffer

BioSealers

Degradable Sealers

Bio Degradable Ball Sealers

BioSealers HR

Degradable Sealers

Bio Degradable Ball Sealers designed for dissolution in static BHT 180°F to 400°F

BioSealers MR

Degradable Sealers

Bio Degradable Ball Sealers designed for dissolution in static BHT 40°F to 200°F.

Boric Acid

Crosslinker - Water

Boric acid solid crosslinking agent for Viking gels

BXL-22WC

Crosslinker - Water

Borate crosslinker with pH buffer-winterized version

C-250

CF - Inhibitor

Filming Amine Corrosion Inhibitor for Calcium Based Brine

Calcium Bromide

Salt

Calcium Bromide Salt

Calcium Chloride,35%

Brine

Calcium chloride brine 35% solution

Calcium Chloride-L

Salt

Calcium Chloride Liquid

Caustic Soda, Dry

pH Control Additive

Solid Sodium Hydroxide

Caustic Soda, Liquid

pH Control Additive

Sodium Hydroxide solution

CB-250

CF - Inhibitor

Corrosion Inhibitors, surface active agents and biocides.

CD-31

Dispersant

Solid cement dispersant and turbulent flow inducer

CD-31L

Dispersant

Liquid cement dispersant and turbulent flow inducer

CD-32

Dispersant

Solid surfactant enhanced Napthalene Sulfonic Acid, cement dispersant and turbulent

CD-32L

Dispersant


CD-33

Dispersant

Solid cement dispersant and turbulent flow inducer

CD-33L

Dispersant


Cello-Flake

Lost Circulation

Cellophane flake lost circulation agent

Cement ASTM Type I

Cement

Corresponds to API Class A, Normally mixing density 15.2 to 15.6 ppg

Cement ASTM Type III

Cement

Corresponds to API Class C, Normally mixing density 14.8 ppg

Cement Class A

Cement

Is used from surface to 6000'




APPLICATION

DESCRIPTION

Cement Class B

Cement

Normally used from surface to 6000'

Cement Class C

Cement

Normally used from surface to 6000'

Cement Class G

Cement

Intended for use from surface to 8000' as a basic cement

Cement Class G, Dyckerhoff

Cement

Intended for use from surface to 8000' as a basic cement (Europe)

Cement Class H

Cement

Intended for use from surface to 8000' as a basic cement

Cement Premium H

Cement

Class H cement

Cement Premium II

Cement

Normally used from surface to 6000', basically Type II Cement

Cement Slag

Special Cement

Cement slag for Blast Furnace Slurries

CI-11

Inhibitor - Acid

Organic and organic/HF acid corrosion inhibitor

CI-14

Inhibitor - Acid

Corrosion inhibitor low temperture

CI-25

Inhibitor - Acid

Corrosion inhibitor for all metals from 200-350°F (95-176°C), 28% HCl and HCl/HF

CI-27

Inhibitor - Acid

Corrosion Inhibitor, Use at moderate to high temperatures (300°F +)

CI-28

Inhibitor - Acid

Corrosion Inhibitor, Use at moderate to high temperatures (300°F +)

CI-30

Inhibitor - Acid

Acid corrosion inhibitor for high temperatures to 400°F (205°C), and chrome steels

Clay Master-5C

Clay Control

Clay control agent to control hydratable or sloughing clays

Clay Treat-3C

Clay Control-KCl sub

KCl substitute for water base hydraulic fracturing

CSE

Bonding


CSE-2

Bonding


DCE-1

CF - Viscosifier

Surfactant gel for Divert C

DCP-1

CF - Viscosifier

Cationic cellulosic polymer, used for stability of Divert C

Defoamer

CF - Defoamer

Blended alcohol base compound

Diacel LWL

Fluid Loss - Cement

Cellulose base cement fluid loss agent, retarder, and spacer additive

Diatomaceous Earth

CF - Filter Media

Cement extender similiar to pozzolan or a filter media for completion fluids

Dicalite Speed Plus

Filter Media

Cement extender similiar to pozzolan or a filter media for completion fluids

Divert C

Blocking Agent

Non-polymer acid diverter, used in many fluids as a diverting solution

Divert III

Blocking Agent

Benzoic acid diverter for acid systems

Divert S

Gellant - Acid

Self-diverting acid -- as acid strength is reduced (as acid spends) -the fluid builds

Divert VI

Blocking Agent

Wax diverting agent

DSGA Liquid Polymer

Gellant - Acid

Drilling Specialities Liquid gelling agent for acid

DSGA Polymer

Gellant - Acid

Drilling Specialities Acid gelling agent.

E-2

Emulsifier

Emulsifier for Polyemulsion Frac

E-31

Emulsifier

Emulsifier for water, acid and hydrocarbon (cationic)

EC-1

Bonding

Cement expansion additive for low to moderate temperatures

EC-2

Bonding

Cement expansion additive for high temperatures

Enzyme S, GBW-16C

Breaker - Water

Starch specific enzyme breaker

ES-3

Solvent

Synthetic, high quality, non-toxic fluid with many of the same attributes as diesel and

FAO-250

Foaming Agent

Foaming agent for oil base fluids

FAW-1

Foaming Agent

Stimulation foaming agent, do not use in systems containing diesel

FAW-18W

Foaming Agent

Non-ionic de-emulsifier for acid

FAW-20

Foaming Agent

General purpose cement foaming agent

FAW-21

Foaming Agent

Foaming agent for acids and ammonium chloride brines




APPLICATION

DESCRIPTION

FAW-4

Foaming Agent

Foaming agent for slurried polymer gels

FAW-5

Foaming Agent

Fresh water foaming agent

FerroFree™

Iron Control

Environmentally friendly, biodegradable

Ferrotrol 1000

Iron Control

Acid chelating agent, may be used in all acids, including HCl/HF

Ferrotrol 200

Iron Control

Ferric iron reducing agent

Ferrotrol 210

Iron Control

Ferric iron reducing agent, for HCl/HF and HCl <20%

Ferrotrol 210C

Iron Control

Ferric iron reducing agent, for HCl/HF and HCl <20%

Ferrotrol 260L

Iron Control


Ferrotrol 262L

Iron Control


Ferrotrol 280L

Iron Control

Proprietary ferric iron reducing agent

Ferrotrol 300

Iron Control

Anhydrous citric acid iron chelating agent

Ferrotrol 300L

Iron Control

Liquid citric acid iron chelating agent, 1 gal = 5 lb Citric acid

Ferrotrol 700

Iron Control


Ferrotrol 800

Iron Control


Ferrotrol 800L

Iron Control


Ferrotrol 810

Iron Control


Ferrotrol 900

Iron Control

EDTA chelation agent, same chemistry as Ferrotrol 1000, 700, and 900L

Ferrotrol 900L

Iron Control


FL-25

Fluid Loss - Cement

General purpose cement fluid loss agent for primary and remedial cementing

FL-52

Fluid Loss - Cement

Polymeric cement fluid loss agent for low to medium density extended slurries

FL-52A

Fluid Loss - Cement

Polymeric cement fluid loss agent for low to medium density extended slurries

FL-63

Fluid Loss - Cement

Polymeric cement fluid loss and gas migration control agent to 350°F (175 C)

FL-66

Fluid Loss - Cement

Polymeric cement fluid loss and gas migration control agent to 350°F (175 C)

FL-66L

Fluid Loss - Cement

Liquid cement fluid loss and gas migration control agent to 350°F (175 C)

FL-67L

Fluid Loss - Cement

Liquid cement fluid loss and gas migration control agent to 350°F (175 C)

FLC-17

Fluid Loss - Stim

Liquid, solids free fluid loss agent for water-based fracturing fluids

FLC-42

Fluid Loss - Stim

Degradable starch fluid loss additive--100% soluble, No internal breaker

FLC-7

Fluid Loss - Stim

Non-damaging fluid loss aditive, only use Northeast Region USA

FlexSand™ HS

Proppant Flowback

For high closure stress and temperatures

FlexSand™ LS

Proppant Flowback

Controls proppant flowback and reduces the effect of stress on the proppant grains.

FlexSand™ MSE

Proppant Flowback

Controls proppant flowback and reduces the effect of stress on the proppant grains.

Flo-Back 20™

Surface Tension

Non-Ionic surfactant for fracturing and matrix acidizing

Flo-Back 30™ Flow Guard LC FLR-1

Surface Tension Lost Circulation Fluid Loss - Cement

FLR-1L

Fluid Loss - Cement

Zwetter-ionic surfactant for fluid recovery Liquid permanent loss circulation agent for non-productive thief zones Retarding, non-viscosifying fluid loss additive for high temperature cement slurries Retarding, non-viscosifying liquid fluid loss additive for high temperature cement

Fly Ash (Pozzolan)

CMT Extender


Artificial Pozzolan cement extender



APPLICATION

DESCRIPTION

Fly Ash L (Pozzolan L)

CMT Extender

Artificial Pozzolan cement extender, lower bulk weight than existing Fly Ash

Formic Acid

Acid - Organic

Liquid intensifier for CI-25 and CI-27 acid corrosion inhibitors, best for carbon steels

FP-11

Anti-Foam

Powdered de-foamer for cement slurries

FP-12L

Anti-Foam

Silicon, oil based emulsion used as a cement de-foamer

FP-13L

Anti-Foam

Oil based, water dispersible cement de-foamer

FP-6L

Anti-Foam

Inexpensive liquid cement defoamer used to control surface foam

Frac-Cide 3

Biocide

Liquid biocide, primary use in linear gel and fresh water, carbamate based

FRO-18

Friction Reducer

Friction reducer for hydrocarbons

FRS-12

Friction Reducer

Metal to metal friction reducer in sea-water, brines and muds

FRW-14

Friction Reducer

Friction reducer for water and light brines

FRW-15

Friction Reducer

Friction reducer for water

FRW-15A

Friction Reducer

Friction reducer for water

FSA-1

Clay Control

Acid fines stabilizer and clay control

Fumaric Acid

pH Control Additive

Weak acidic buffer for fracturing systems

GBA-2

Breaker - Acid

Slow release solid breaker for crosslinked acid

GBA-3

Breaker - Acid

Slow release solid breaker for crosslinked acid

GBO-6

Breaker - Oil

Solid breaker for Super Rheo Gel systems

GBW-12CD

Breaker - Water

Enzyme breaker concentrate for Enzyme G, Enzyme G-LpH

GBW-14C

Breaker - Water

Enzyme breaker concentrate for Xantham

GBW-15C

Breaker - Water

Liquid enzyme breaker concentrate for high pH guar and celloluse based fluids

GBW-16C, Enzyme S

Breaker - Water

Starch specific enzyme breaker

GBW-18

Breaker - Water

Solid oxidizing breaker for water based polymers

GBW-20C

Breaker - Water

Enzyme breaker concentrate for Northeast Region

GBW-23

Breaker - Water

High tempature delayed release breaker

GBW-24

Breaker - Water

Moderate tempature delayed release breaker

GBW-26C

Breaker - Water

Enzyme breaker concentrate for Enzyme C-HT

GBW-33D

Breaker - Water

Solid enzyme breaker for high pH guar based fluids

GBW-5

Breaker - Water

Solid oxidizing breaker for water based polymers

GBW-7

Breaker - Water

Solid oxidizing breaker for remedial treatments

GM-55

Gellant - Methanol

HPG Gelling Agent for 100% Methanol

GO-64

Gellant - Oil

Oil gelling agent for Super Rheo Gel

Granular Sugar

Retarder

Retarder for cement

GS-1A

Gel Stabilizer

Sodium thiosulfate gel stabilizer

GS-1L

Gel Stabilizer

Liquid thiosulfate gel stabilizer

GW-21

Gellant - Water

HEC (Hydroxyethyl Cellulose) gelling agent, HEC-25

GW-22

Gellant - Water

Clarified, purified Xanthan gum gelling agent

GW-22L

Gellant - Water

Clarified, purified Xanthan gum gelling agent slurry

GW-24LE

Gellant - Water

Slurried HEC (Hydroxyethyl Cellulose) gelling agent, slurried in an environmentally

GW-27

Gellant - Water

Refined guar gum gelling agent

GW-27LE

Gellant - Water

Guar gum slurry gelling agent, slurried in an environmentally friendly carrier

GW-28

Gellant - Water

CMHEC (Carboxymethyl Hydroxyethyl Cellulose) gelling agent




APPLICATION

DESCRIPTION

GW-28KF

Gellant - Water

Highly concentrated liquid dispersion of a high quality, anionic, water soluble polymer

GW-28LC

Gellant - Water

CMHEC slurry

GW-28LE

Gellant - Water

CMHEC slurried in an environmentally friendly carrier

GW-3

Gellant - Water

Guar gum gelling agent

GW-32

Gellant - Water

HPG (Hydroxyproply Guar) gelling agent

GW-37

Gellant - Water

Drilling grade xanthan coated with a dispersant

GW-37L

Gellant - Water

Drilling grade xanthan coated with a dispersant in a glycol solution

GW-38

Gellant - Water

CMHPG (Carboxymethyl Hydroxyproply Guar) gelling agent

GW-38L

Gellant - Water

CMHPG (Carboxymethyl Hydroxyproply Guar) gelling agent with buffer

GW-3L

Gellant - Water

Guar gum slurry gelling agent with buffer

GW-3LC

Gellant - Water

Guar gum slurry gelling agent with buffer

GW-3LD Green

Gellant - Water


GW-3LE

Gellant - Water


GW-4

Gellant - Water

Guar gum gelling agent

GW-4 AFG

Gellant - Water

Guar gum gelling agent, for North Sea, Fine ground

GW-45

Gellant - Water

CMG (CarboxyMethyl Guar) gelling agent

GW-46

Gellant - Water

CMG (CarboxyMethyl Guar) gelling agent

GW-46L

Gellant - Water

CMG gum slurry gelling agent

GW-4LD

Gellant - Water

Guar gum slurry gelling agent

HCl Acid

Acid - HCL

Hydrochloric Acid

Hematite

Weighting Materials

Cement and spacer weighting agent

High Perm CRB

Breaker - Water

Encapsulated Oxidixing breaker for water base gels

High Perm CRB-LT

Breaker - Water

Encapsulated Oxidixing breaker low-moderate temperatures

High Perm CRE

Breaker - Water

Delayed release enzyme breaker slurry

High Perm KP

Breaker - Water


High Perm KP-HT

Breaker - Water


HS-2

Inhibitor - Sulfide

Hydrogen sulfide complexer

HS-3

Inhibitor - Sulfide

Non-ionic, Hydrogen sulfide complexer

HS-4

Inhibitor - Sulfide

Non-ionic, Hydrogen sulfide complexer, (North Sea Usage)

HT Vis 508

CF - Viscosifier

Viscofier for completion fluids

HT Vis 708

CF - Viscosifier

Viscofier for Completion Fluids

HTI-2001

CF - Inhibitor

Sulfur-free, amine-free corrosion inhibitor for use in brines

Hy Temp 382

Inhibitor - Intensifier

Intensifier for CI-25 acid corrosion inhibitor, for inorganic and organic acids

Hy Temp 410


Intensifier, not for 28% HCl

Hy Temp I


Solid intensifier for CI-25 and CI-27 acid corrosion inhibitors for HCl and HF

Hy Temp O


Liquid intensifier for CI-25 and CI-27 acid corrosion inhibitors, best for carbon steels

Hyperm NoMul C

CF - Inhibitor

Special surfactants that are designed to inhibit the formation of completion fluid-in-oil

Hyperm NoMul Z

CF - Inhibitor

Special surfactants that are designed to inhibit the formation of completion fluid-in-oil

Inflo-102

Surface Tension

Cationic and nonionic surfactants for water based fracturing fluids




APPLICATION

DESCRIPTION

Inflo-150

Surface Tension

Nonionic surfactant for water based fracturing fluids

IPA (Isopropanol)

Alcohol

Isopropyl Alcohol (IPA)

KCl Free

Special Additive

Non-accelerating clay control agent for cement slurries

Kol Seal

Lost Circulation

Coarse ground coal lost circulation agent.

LCM-1

Lost Circulation

Particulate asphaltene bridging material used to control lost circulation

LiteProp™ 125

Proppant - Lite

Ultra Low density proppant

Lite-Wate T

Cement

Manufactured light-wieght cement, Normally mixed from 12.5 to 14.5 ppg without

LSA-1

Liquid Stone

Acceleraror for Liquid Stone

LSA-3, PMC-10

Liquid Stone


LSA-4

Liquid Stone

Acceleraror for Liquid Stone, Calcium chloride salt

LSA-5

Liquid Stone


LSP-1

Liquid Stone

Plastizer for Liquid Stone

LSP-2

Liquid Stone

Plastizer for Liquid Stone, replaces LSP-1

LSR-1

Liquid Stone

Retarder for Liquid Stone

LSS-1

Liquid Stone

Suspending agent for Liquid Stone

LSS-2

Liquid Stone

Suspending agent for Liquid Stone

LT-21

Surface Tension

Non-ionic silt-suspender for water, acid, and brines

LT-32

Surface Tension

Non-ionic Surfactant for water, acid, oil, or brine

LW-6

CMT Extender

Ceramic microsphere cement extender

LW-7-10

CMT Extender

Glass bubbles 10,000 psi burst

LW-7-4

CMT Extender

Glass bubbles 4000 psi burst

LW-7-6

CMT Extender

Glass bubbles 6000 psi burst

Magnacide 575

Biocide

Liquid environmentally friendly biocide, Completely new class of antimicrobial

Magne Plus Cement

Lost Circulation

Settable lost circulation control system for temperatures from 140°F (60°C) to 225°F

Magne Plus LT Cement

Lost Circulation

Settable lost circulation control system for temperatures < 140°F ( 60°C )

Max Seal

Lost Circulation

Low density, shredded rubber, fibrous material for use as lost circulation material

MCS-D

Spacer Surfactant

Dry Surfactant for MCS cement spacer systems, Used in Alaska only

Methanol

Alcohol

Reduce surface tension in acid or water systems

MPA-1

Special Additive

Fine white pozzolanic powders used to enhance various cement properties

MPA-3

Special Additive

Used to enhance slurries flexural strength

MS-16

Solvent

Non-ionic mutual solvent, de-emulsifier, water block breaker, water wetter

Mud-Save F

Lost Circulation

Lost circulation agent, Synthetic Rubber

Mud-Save M

Lost Circulation

Lost circulation agent for mud, Coarse material

Naphtha, aromatic hi-flash

Solvent

Aromatic naphtha solvent

NE-110W

Non-Emulsifier

Anionic surfactant for water, acid, oil, or brine

NE-118

Non-Emulsifier

Non-ionic surfactant for water, acid, oil, or brine

NE-13

Non-Emulsifier

Cationic and non-ionic de-emulsifier for acid or oil

NE-23

Non-Emulsifier

Anti-sludge preventer and non-emulsifier in acid stimulation treatments

NE-940

Non-Emulsifier

Non-ionic de-emulsifier for acid, water, or brine




APPLICATION

DESCRIPTION

Nitrogen Liquid N2

GAS

Liquid nitrogen

OA-13

CF - Surfactant

Bleach concentrate

OB-1 Emulsifier

Spacer Surfactant

Emulsifier for OB-1 cement/mud spacer

OS-8

CF - Oxygen Scav


Paravan 25

Paraffin Dispersant

Biodegradable, essentially non-toxic, high boiling alternative to solvents.

Perfalite

Lost Circulation

Lost circulation agent

Perlite

Lost Circulation

Perlite cement extender

PF-2

Inhibitor - Packer

Water soluble corrosion and scale inhibitor, with oxygen scavenger

Potassium Chloride (KCL)

Salt

Potassium Chloride Salt

Potassium Chloride Brine,

Brine

Potassium Chloride 24% Solution

Quick Vis

CF - Viscosifier

Non ionic, high molecular weight hydrophilic polymer viscosifier (HEC)

R-18

Retarder

Retarder for thixotropic and sodium metasilicate extended slurries

R-21

Retarder

Cement retarder for low to medium temperatures.

R-21L

Retarder

Liquid cement retarder for low to medium temperatures.

R-3

Retarder

Low temperature, solid, non-dispersing cement retarder, may be dissolved in water

R-7

Retarder

Cold Set cement retarder

R-8

Retarder

High temperature solid cement retarder

R-8L

Retarder

High temperature liquid cement retarder, can be added to mix water

S-150

Surfactant

Blend of amphoteric and non-ionic surfactants

S-301

Surfactant

Anionic and non-ionic surfactant for water and acid

S-351

Surfactant

Multi-purpose surfactant, flow back and non-emulisifier

S-400

Surfactant

Nonionic surfactant for water, brines, acid, and oil

S-8, Silica Flour

Sand

200 mesh silica

S-8C,Sand,100 mesh

Sand

100 Mesh Sand

Salt-Coarse

Blocking Agent

Sodium Chloride is an excellent internal diverting agent, typically 0-20 mesh

Salt-Medium

Blocking Agent

Sodium Chloride

Saltrol 2

Inhibitor - Brine

Salt inhibitor is a patented water soluble formulation.

Salt-Trimix

Blocking Agent

Graded rock salt diverting agent

Sand (Cement Applications)

Sand

Sand used in cement applications

Sand, All Purpose

Sand

General purpose sand

SAPP

Completion

Dispersant for most water base muds

SC Resin Base 1330

Sand Control

Used in SC Resin II

SCB-100

CF - Scale Inhibitor

Recommended for CaCO3, MgCO3, and CaSO4 scales and high temperature

Seal (Coarse)

CF - Fluid Loss

Fluid Loss control coarse grade

Seal (Fine)

CF - Fluid Loss

Fluid Loss control fine grade

Seal (Medium)

CF - Fluid Loss

Fluid Loss control medium grade

Sodium Acetate

pH Control Additive

Sodium acetate, low pH buffer

Sodium Bicarbonate

pH Control Additive

Solid, high pH buffer

Sodium Borate

Crosslinker - Water

Sodium borate solid crosslinking agent for Viking gels

Sodium Bromide

Salt

Sodium Bromide Salt

Sodium Carbonate

pH Control Additive

Solid high pH buffer

Sodium Chloride, Fine

Salt

Sodium Chloride, 100 mesh




APPLICATION

DESCRIPTION

Sodium Diacetate

pH Control Additive

Solid low pH buffer, readily disolvable in water.

Sodium Hypochlorite,12%

Biocide

Bleach concentrate

Sodium Metasilicate

CMT Extender

Dry cement extender

Sodium Silicate, Liquid

CMT Extender

Liquid cement extender

SS-10

CF - Surfactant

Proprietary formulation designed to combine with hydrogen sulfide to form stable,

SS-2

Spacer Surfactant

Surfactant for cement spacer systems

Static Free

Special Additive

Anti-static additive for proppants and dry cement

STPP

Completion

Mud removal agent

Sulfamic Acid

pH Control Additive

Low pH buffer, weak acid

Super Vis LD (OLS)

CF - Viscosifier

High quality polymer dispersed in an organic liquid

Super Vis-EF

CF - Viscosifier

Highly concentrated liquid dispersion of a high quality, pre-activated, nonionic, water

Toluene

Solvent

Aromatic solvent for oilfield chemicals

Ultra Flush II Concentrate

Spacer Surfactant

Concentrate for Ultra-Flush II

Ultra Vis

CF - Viscosifier

Highly concentrated (10.5 lbs per 5 gallons) HEC in organic potassium salt solution

Ultraprop

Proppant - Ceramic

A man-made ceramic proppant with improved conductivity and strength

US-2

Solvent

Mutual solvent for acidizing, requires lower loadings than Inflo-40

US-40

Solvent

Non-ionic mutual solvent, water wets, helps prevents emulsions

Versaprop

Proppant - Ceramic

A man-made ceramic proppant with improved conductivity and strength.

W-10

Weighting Materials

Cement weighting agent, Manganese Fume

WCB-1

Water Control

Aids in adhesion of Aquacon polymer to formations

Well Wash 100

CF - Displacement

Efficiently removes and disperses mud cake and residues

Well Wash 200

CF - Displacement

high flash naphtha distillate with exceptional oil and grease solvent properties

Well Wash 2000

CF - Displacement

Removes oil based drilling mud and oily film residue from casing, pipe and exposed

Well Wash 2050

CF - Displacement

Blend of surfactants to aid in the removal of mud, pipe dope, oil, sand, barite and

Well Wash 2100

CF - Displacement

A sythnetic and oil-based mud cleansing agent

Well Wash 3000

CF - Displacement

Synthetic and oil-based mud weighted-spacer surfactant

Well Wash 3500

CF - Displacement

Synthetic and oil-based mud weighted-spacer surfactant

Well Wash 400

CF - Displacement

Pickling agent prior to perforating, stimulation, or gravel pack operations to remove

Well Wash 4500

CF - Displacement

Displacement chemical for synthetic oil base muds

X-Cide 207

Biocide

Solid granular biocide, Isothiazoline based

X-Cide 5009

Biocide

Dry biocide providing quick kill, bromide based

XLA-2

Crosslinker - Acid

Liquid zirconium crosslinker for XL Acid II and EAS.

XLD-1

Crosslinker Delay

Crosslink Delayer for High pH fluids

XLD-2

Crosslinker Delay

A liquid crosslink time delayer used in Deep Spot Acid systems

XLD-30

Crosslinker Delay

Crosslink time delayer for XLW-30

XLO-5

Crosslinker - Oil

Crosslinker for Super Rheo Gel

XLW-14

Crosslinker - Water

Zirconium crosslinker for Medallion HT gels

XLW-22C

Crosslinker - Water

Zirconium crosslinker for Medallion gels

XLW-24

Crosslinker - Water

Borate crosslinker for Spectra Frac G gels




APPLICATION

DESCRIPTION

XLW-30

Crosslinker - Water

Borate crosslinker for Viking D gels

XLW-30A

Crosslinker - Water

Borate Crosslinker for Viking ID

XLW-32

Crosslinker - Water

Liquid borate crosslinker for Viking gels

XLW-4

Crosslinker - Water

Borate crosslinker for Viking gels

XLW-40

Crosslinker - Water

Crosslinker for 100% methanol system for West Texas

XLW-41

Crosslinker - Water

Titanium based crosslinker

XLW-45

Crosslinker - Water

Titanium surface crosslinker for Medallion HT gels

XLW-49

Crosslinker - Water

Zirconium crosslinker for Clean Plug

XLW-56

Crosslinker - Water

Borate crosslinker for Spectra Frac G gels

XLW-60

Crosslinker - Water

Zirconium crosslinker for Medallion gel systems

Xylene

Solvent

Aromatic solvent for oilfield chemicals

Zinc Bromide Brine,17

Brine

Zinc Bromide solution used for heavy weight solutions

Zinc/Calcium Bromide

Brine

Zinc/Calcium Bromide used for heavy weight clear solutions



BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS ACIDIZING Acid – Crosslinked Acid – Emulsified Acid – Gelled Acid – HCl Acid – HCl-HF Acid – Organic Acid – Retarded Acid Additive Acid System Alcohol Anti – Sludge Blocking Agent Breaker – Acid

PAGE 2 PAGE 2 PAGE 2 PAGE 2 PAGE 2 PAGE 2 - 3 PAGE 3 PAGE 3 PAGE 3-4 PAGE 4 PAGE 5-6 PAGE 4 PAGE 5

Breaker System Chemical Retarder Clay Control Completion Crosslinker – Acid Crosslinker Delay Degradable Sealer Emulsifier Foaming Agent Friction Reducer Gellant - Acid Gellant - Water Inhibitor - Acid

PAGE 5 PAGE 5 PAGE 5 PAGE 6 PAGE 6 PAGE 6 PAGE 6 PAGE 6 PAGE 7 PAGE 7 PAGE 7-8 PAGE 8 PAGE 8-9

Inhibitor - Brine Inhibitor - Intensifier Inhibitor - Sulfide Iron Control Miscellaneous Non-Emulsifier Paraffin Dispersant Salt Scale Solvent Solvent Surface Tension Surfactant Water Control

PAGE 9 PAGE 9 PAGE 9 PAGE 9-10 PAGE 11 PAGE 11 PAGE 11-12 PAGE 12 PAGE 12 PAGE 12-13 PAGE 13 PAGE 13 PAGE 14

CEMENTING Anti – Foam Bonding Cement Cement Extender Dispersant Fluid Loss - Cement

PAGE 15 PAGE 15-16 PAGE 17 PAGE 17-18 PAGE 19 PAGE 119

Liquid Stone Lost Circulation Retarder Salt Sand Spacer

PAGE 20 PAGE 20-21 PAGE 22 PAGE 22 PAGE 22-23 PAGE 23

Spacer Surfactant Special Additive Special Cement Weighting Material

PAGE 23 PAGE 24 PAGE 24-25 PAGE 25

CF – Fluid Loss CF – Inhibitor CF – Oxygen Scavenger CF – Packer Fluid

PAGE 27 PAGE 27 PAGE 28 PAGE 28

CF – Scale Inhibitor CF – Surfactant CF – Viscofier

PAGE 28 PAGE 28 PAGE 28-29

COMPLETION FLUID CF – Brine CF – Defoamer CF – Displacement CF – Filter Media

PAGE 26 PAGE 26 PAGE 26 PAGE 26-27

STIMULATION Biocides Breaker – Oil Breaker – Water Breaker Catalyst Breakers System Crosslinker - Oil Crosslinker - Water

PAGE 31 PAGE 31 PAGE 31-34 PAGE 34 PAGE 34-35 PAGE 35 PAGE 35-36

Foam System Frac - Methanol Frac - Oil Frac - Water Friction reducer - Steel Gel Stabilizer Gellant - Methanol

PAGE 37 PAGE 37 PAGE 38 PAGE 38 PAGE 38 PAGE 39 PAGE 39

Gellant - Water Miscellaneous Oil Emulsion pH Control Additive Proppant - Flowback Resin Activator Salt

PAGE 39-42 PAGE 42 PAGE 42 PAGE 42-43 PAGE 43 PAGE 43 PAGE 43

Crosslinker Delay Fluid Loss - Stim

PAGE 37 PAGE 37

Gellant - Oil Gellant - Surfactant

PAGE 39 PAGE 39

Sand Control

PAGE 43-44



BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Acid - Crosslinked Deep Spot

Retarded acid system with leakoff control Can be combined with aromatic solvents, or foamed with CO2 and Nitrogen Capable of carrying proppants 3 to 28% Hydrochloric Acid 15-20 gals per thousand

Deep Spot Delayed

Retarded acid system with delayed crosslink and excellent leakoff control Can be combined with aromatic solvents, or foamed with CO2 and Nitrogen Capable of carrying proppants 3 to 28% Hydrochloric Acid 15-20 gals per thousand

Acid - Emulsified Emulsified Acid

Acid in diesel emulsion to retard reaction rate of HCl Works with 7.5%-28% mixed with diesel, kerosene or some crude oils Stable to 225°F (107°C)

Acid - Gelled Gelled Acid

Xanthan based gelled acid system Limited to 15% Acid and 200°F (93°C) Retards acid, reduces friction and fluid loss

Gelled Acid 200

Gelled acid system for up to 28% HCL and 300°F Acid frac applications, lowers friction pressure Suspension of insoluble fines 5-40 gpt AG-12

Acid - HCl HCl Acid

Hydrochloric Acid Used to stimulate carbonate formations Or to break down perforations 3 to 28 % as HCl

Acid - HCl/HF HCl-HF Acid

Mixture of Hydrochloric & Hydrofluoric acid Used to stimulate sandstone formations

Acid - Organic Acetic Acid 0.1-10%

Commonly called perforating acid Can be used to stimulate carbonate reservoirs Very slow reaction rate as compared to Hydrochloric acid Do not use above 20% by weight.

Acetic Acid 10.1-15%

Commonly called perforating acid Can be used to stimulate carbonate reservoirs Very slow reaction rate as compared to Hydrochloric acid Do not use above 20% by weight. Commonly called perforating acid Can be used to stimulate carbonate reservoirs Very slow reaction rate as compared to Hydrochloric acid Do not use above 20% by weight. Glacial acetic acid low pH buffering agent, also used as acetic acid to 20% Buffering action improves performance of other Ferrotrol agents, not effective alone Same chemistry as acetic anhydride blend, may be used in Medallion Frac 5 to 20 gal / 1000 gal acid (use with Ferrotrol 300, 300L, 800, 800L, or 810)

Acetic Acid 15.1-20%

Acetic Acid/Glacial



BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Acid - Organic Acetic Anhydride Blend

Formic Acid

Perforating Acid 10% Acetic

Weighted Acetic Acid

Acetic acid /acetic anhydride mixture buffering agent, also used as acetic acid to 20% Buffering action improves performance of other Ferrotrol agents, not effective alone Same chemistry as glacial acetic acid, may be used in Medallion Frac 5 to 20 gal / 1000 gal acid (use with Ferrotrol 300, 300L, 800, 800L, or 810) Liquid intensifier for CI-25 and CI-27 acid corrosion inhibitors, best for carbon steels Effective to 350°F (175°C), use with inorganic acids, OK to filter Add to mix water or acid, less effective for chrome steel: use Hy Temp I or 382 5 to 100 gal / 1000 gal acid Acetic acid system 10% Can be used to stimulate carbonate reservoirs Very slow reaction rate as compared to Hydrochloric acid Do not use above 20% by weight. 10% Acetic acid weighed with calcium chloride Maximum weight is 12 lbs/gal

Acid - Retarded Sta-Live Acid Hi-Temp

Sta-Live Acid Lo-Temp

Chemically retarded acid system for use above 200°F (93°C) Extends the reaction rate and improves fracture etching Retarded by chemical absorbsion 10 gpt SLA-48 Chemically retarded acid system for use below 200°F (93°C) Extends the reaction rate and improves fracture etching Retarded by chemical absorbsion 6 gpt SLA-48

Acid Additive HV Acid

Component of BJ Sandstone acid 15 or 30 gpt typical, in BJ Sandstone Acid

Acid System BJ Sandstone Acid

One Shot Plus

Pentol 100

Pentol 150

Pentol 200

Pentol 250

Pentol 300

Pentol 350


Retarded HCl / HF acid system Significantly slows HF reaction rate Reduces formation unconsolidation 4 systems to meet individual requirements Used for treating oil coated acid soluble scales and organic deposits Solvent in acid dispersion Removes oil and Organic deposits from acid soluble materials 10 to 50 % Solvent in any aqueous acid HCl Acid system containing 100 gpt Pentafax 2 and a blend of dispersants and surfactants. 100 gpt Pentafax 2 HCl Acid system containing 150 gpt Pentafax 2 and a blend of dispersants and surfactants. 150 gpt Pentafax 2 HCl Acid system containing 200 gpt Pentafax 2 and a blend of dispersants and surfactants. 200 gpt Pentafax 2 HCl Acid system containing 250 gpt Pentafax 2 and a blend of dispersants and surfactants. 250 gpt Pentafax 2 HCl Acid system containing 300 gpt Pentafax 2 and a blend of dispersants and surfactants. 300 gpt Pentafax 2 HCl Acid system containing 350 gpt Pentafax 2 and a blend of dispersants and surfactants. 350 gpt Pentafax 2


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Acid System S-Cubed

Super Sol

Weighted HCl Acid

Combines matrix acidizing and scale inhibition technologies. Removes many precipitates and naturally occurring minerals to reduce skin damage. Stimulation without damage from precipitates. Acid system for deep hot carbonate reservoirs where full strength acid is desired Provides retarded, easily inhibited acid with reacting capacity of 10, 15, 20 or 30% HCl Less corrosive than equivalent HCL concentration Four formulations using Acetic or formic Acid Acid system weighed with various inorganic salts Salt choice depends on target density and system cost effectiveness

Alcohol IPA (Isopropanol)

Methanol

Isopropyl Alcohol (IPA) Reduce surface tension in acid or water systems Break water blocks, water wet formation fines Used in concentrations up to 20% by volume. Used as a solvent Reduce surface tension in acid or water systems Break water blocks, water wet formation fines Oxygen scavenger to improve temperature stability 10% by vol as frac gel stabilizer 20-50% by volume for surface tension reduction and water block removal

Anti-Sludge AS-66

SJAS-10

Acid Anti-Sludge Agent and water wetter, non-emulsifier Cool down pad recommended above 180°F (82°C) 5 to 60 gpt Normal use 10 to 20 gpt proven to be effective Incompatible with admiralty brass, copper, ductile steel & mild steel. Do not use with Cationic material will result in serious compatibility difficulties Anti-sludge package for the West Coast region

SJAS-15

Anti-sludge package for the West Coast region

SJAS-20

Anti-sludge package for the West Coast region

Blocking Agent Benzoic Acid

Divert C Divert III

Divert VI

Divert VII

Divert VIII


Temporary diverting agent in either producing or injection wells Also Used as an Oil Gel Breaker Used in FLC-18 (Divert III) and Divert VII Generally used in 5-12 lb/ft of pay for diverting or 0.1-2 ppg of fluid as breaker. Melts at 242-252°F Non-polymer acid diverter, used in many fluids as a diverting solution provides a residue free way to divert fluids for optimized stimulation and sand control applications Benzoic acid diverter for acid systems Benzoic Acid in Ammonium Hydroxide 100 to 200 gal / 1000 gal Wax diverting agent Oil Soluble, Melts at 150°F to 160°F (65°C to 71°C) 0.25 to 1.0 lb / gal Water clear solution that forms a white precipitate when added to aqueous solutions The precipitate is soluble in oil, water and gas Rule of thumb 25 gallons per perforation at 4 gpt solution Water clear solution that forms a white precipitate when added to aqueous solutions The precipitate is soluble in oil, water and gas Rule of thumb 25 gallons per perforation at 4 gpt solution


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Blocking Agent Salt-Coarse

Sodium Chloride is an excellent internal diverting agent, typically 0-20 mesh no temperature limitations and is transported in a gelled 10 ppg brine Its particle size is specifically designed for good blocking action. Concentrations range from 10-20 lb/ft of pay or 0.5-2 ppg of fluid. Sodium Chloride 4-10 mesh It has no temperature limitations Concentrations range from 10-20 lb/ft of pay or 0.5-2 ppg of fluid.

Salt-Medium

Salt-Trimix

Graded rock salt diverting agent Water Soluble, Well Graded Rock Salt Size Ranges From 0.002 to 0.25 inches 0.5 to 4.0 lb / gal in Perforated Sections 10 to 25 lb / ft in Open Hole Sections

Breaker - Acid GBA-2

GBA-3

Slow release solid breaker for crosslinked acid Used for Deep Spot Acid systems Coated inorganic material for use to 225°F (110°C) 10 to 30 lb / 1000 gal Slow release solid breaker for crosslinked acid Used for Deep Spot Acid systems Coated inorganic material for use to 150°F (65°C) 5 to 20 lb / 1000 gal

Breaker System Mudzyme S/X One Step (Acetic)

Mudzyme S/X One Step

Enzyme breaker fluid system to remove starch and Xanthan polymer damage From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-8 pH Hole volume plus 20% Enzyme breaker fluid system to remove starch and Xanthan polymer damage (Formic) From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-8 pH Hole volume plus 20%

Chemical Retarder SLA-48

Anionic and non-ionic surfactant Acid retarder for Sta-Live Acid Water wets from water or brine 6 to 10 gal / 1000 gal

Clay Control Clay Master-5C

FSA-1

Clay Treat-3C


Clay control agent to control hydratable or sloughing clays Use for hydraulic or acid fracturing and matrix acidizing Helps to stabilize fines, provides long lasting protection 0.25 to 1 gal / 1000 gal Not compatible with Binary or CO2 foams with FAW-4 Acid fines stabilizer and clay control Mobilizes siliceous fines in the formation through siloxane covalent bonds Add to acid mixtures and to water based preflush and overflush fluids 1 to 10 gal / 1000 gal KCl substitute for water base hydraulic fracturing Equivalent to 2% KCl at 1 gpt Effective in controlling clay damage, may be used in matrix acidizing 1 gal / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Completion MRS-1

MRS-3M

SAPP

STPP

Versol II

Versol V

Aqueous completion fluid Clean-up of water based drilling mud damage Potassium chloride base Aqueous completion fluid Clean-up of water based drilling mud damage Sodium chloride base Dispersant for most water base muds Sequesters calcium in mud to prevent flocculation Is used primarily as a preflush to remove mud filter cake Normally used at 100 lbs per 20 bbls water Mud removal agent Sodium Tripolyphosphate Trisodium Phosphate Mud removal agent used in Versol-5 Water based completion fluid Removes damage from oil based muds Basic pH >9 with surface tension 25 dynes/cm Water based completion fluid containing surfactants, detergents, buffers, and sequestrants Removes damage from water based muds Basic pH with surface tension 30 dynes/cm

Crosslinker - Acid XLA-2

Liquid zirconium crosslinker for XL Acid II and EAS. Crosslinker for AG-56L Added to gelled acid on-the-fly, adjustable crosslink time 7 to 9 gal / 1000 gal

Crosslinker Delay XLD-2

A liquid crosslink time delayer used in Deep Spot Acid systems It could be used from 1 to 10 gpt. Typically 3-5 gpt Amount needed increases with the initial fluid temperature at surface and the strength of the acid.

Degradable Sealer BioSealers

BioSealers HR

BioSealers MR

Bio Degradable Ball Sealers Organic-based ball sealers that slowly dissolve in all aqueous fluids. Any application were conventional ball sealers could be used Any aqueous solution Do not store above 85°F Bio Degradable Ball Sealers designed for dissolution in static BHT 180°F to 400°F Organic-based ball sealers that slowly dissolve in all aqueous fluids. Any application were conventional ball sealers could be used Any aqueous solution Bio Degradable Ball Sealers designed for dissolution in static BHT 40°F to 200°F. Organic-based ball sealers that slowly dissolve in all aqueous fluids. Any application were conventional ball sealers could be used Any aqueous solution

Emulsifier E-2

E-31


Emulsifier for Polyemulsion Frac Forms water external emulsion with oils, with low friction pressure Provides viscous emulsion to control leakoff and support proppant 4 to 7 gal / 1000 gal water Emulsifier for water, acid and hydrocarbon (cationic) Forms water external emulsion with oils, with low friction pressure Provides viscous emulsion to control leakoff and support proppant 4 to 7 gal / 1000 gal water


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Foaming Agent FAO-250

FAW-1

FAW-18W

FAW-20

FAW-21

FAW-4

FAW-5

Foaming agent for oil base fluids Creates stable nitrogen foams with diesel, crude oil, xylene, and condensates Water wetting non-ionic surfactant, provides low surface tension 6 to 10 gal / 1000 gal hydrocarbon Stimulation foaming agent, do not use in systems containing diesel Amphoteric foamer for light brines, acid, and dry mix gelled water for foam fracs Water wets sandstone and carbonates, will foam methanol solutions 3-10 gal / 1000 gal Non-ionic de-emulsifier for acid Used in combination with NE-32 to prevent sludging and to break emulsions Foaming agent for water based fluid systems 2 to 5 gal / 1000 gal acid General purpose cement foaming agent Anionic foamer for nitrogen, do not use in acid Effective in stimulation treatments, subject to ionic compatibility 0.7 to 0.8 % by weight of cement slurry; 3-10 gal / 1000 gal stim fluids 0.05 to 0.20 gps with 0.15 being most typical for cement Foaming agent for acids and ammonium chloride brines Amphoteric foamer for foam diverters, and foamed acid Water wets sandstone and carbonates from water and spent acid 3 to 7 gal / 1000 gal Foaming agent for slurried polymer gels Use in Medallion, Spectra Viking, and all foam fracs using XLFC slurries Anionic foamer, compatible with Clapro and Clay Treat-3C 5 to 7 gal / 1000 gal Fresh water foaming agent Not cost effective above temperature limit of 140°F Limited use to the Northeast Region 5 to 7 gal / 1000 gal

Friction Reducer FRO-18

FRW-14

FRW-15

FRW-15A

Friction reducer for hydrocarbons FRO-18 is a oil base friction reducer used in a two component system mixed 50/50 with IPA Normal concentrations of 3 gpt of each component. Friction reducer for water and light brines polymer hydrates rapidly, can be used "on-the-fly" 0.25 to 1.0 gallon per 1000 gallons of base fluid. Friction reducer for water May be Brine Sensitive 0.125 to 1 gallon per 1000 gallons Friction reducer for water May be Brine Sensitive 0.125 to 1 gallon per 1000 gallons

Gellant - Acid Acigel

AG-12

AG-21R


Polymeric acid gellant and friction reducer Quaternized co-polymer in Mineral Oil Emulsion of acrylamide and methacrylate Acid gelling agent, can be used at high-temperatures for hydrochloric acid Stable in 28% HCl for indefinite period Good friction reducer for brine systems 5 to 40 gal / 1000 gal acid Recommend mixing 50:50 with diesel to prevent fish eyes during gelling. HEC (Hydroxyethyl Cellulose) gelling agent, HEC-10 Used primarily in gravel packing fluids, and as an acid gellant Brine compatible, non-wall building polymer 20 to 150 lb / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Gellant - Acid AG-26

Drilling grade Xanthan, hydrates rapidly Low residue, water base, high molecular weight polysaccharide Generates low friction and has low solid content Recommended use is 10-60 lbs/1000 gals in ware, brine or acid based fluids. Strong oxidizers Acid gelling agent for XL Acid III system Synthetic polymer Works as a friction reducer for acid systems. 10 to 20 gal / 1000 gal Requires 2 gpt activator PSA-2L Acid gelling agent for Deep Spot Acid & Deep Spot Delayed Acid system Can be used as friction reducer. Environmentally friendly (North Sea usage) 10 to 20 gal / 1000 gal Will degrade in time with HCl, never mix earlier than 6 hours before pump time. Not compatible with Acetic Acid, oxidizers, iron chealators other than FE-300L, scale inhibitors. Self-diverting acid -- as acid strength is reduced (as acid spends) -- the fluid builds viscosity. Viscosity then drops with continued spending. It builds up and drops again in a higher pH regime, as well Most common applications would be in carbonate matrix and fracture acidizing

AG-57L

AG-58L

Divert S

DSGA Liquid Polymer

DSGA Polymer

Drilling Specialties Liquid gelling agent for acid Stable viscosity, improves fluid loss control and retardation of HCl. Thins with connate water, and provides post-treatment cleanup. BHST from 100°F(37°CC) to 300°F (149°C) all HCl acids strengths from 3-28%. 40-120 pounds per thousand gallons 2.58 lbs of polymer per gallon of liquid gelling agent. Drilling Specialties Acid gelling agent. Stable viscosity, improves fluid loss control and retardation of HCl. Thins with connate water, and provides post-treatment cleanup. BHST from 100°F(37°CC) to 300°F (149°C) all HCl acids strengths from 3-28%. 40-120 pounds per thousand gallons

Gellant - Water GW-37

GW-37L

Drilling grade Xanthan coated with a dispersant Primary function to provide solids transport, solids suspension Friction reduction and improve displacement efficiency Friction reduction 1-2 lbs per bbl fluid Spacer 2-4 lbs per bbl fluid Tri-valent ions such as chromium Drilling grade Xanthan coated with a dispersant in a glycol solution Contains no oil, clay or other solids for maximum environmental protection Primary function to provide solids transport, solids suspension 1 quart is equal to one pound, Spacer two 5 gl pail to 20 bbls fluid Friction reduction one 5 gl pail to 20 bbls fluid, Tri-valent ions such as chromium

Inhibitor - Acid CI-11

CI-14


Organic and organic/HF acid corrosion inhibitor Temperatures to 400°F (205°C) Use with acetic, formic, and citric acids 1 to 10 gal / 1000 gal acid Corrosion inhibitor low temperature Environmental Rating of "C" for North Sea Similar chemistry to CI-27 1 to 30 gals per 1000 gals of Acid


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Inhibitor - Acid

CI-27

CI-28

CI-30

Chrome steel to 325 F (150°C) only, compatible with mutual solvents Intensifier required at high temperatures, not compatible with NE-32 1 to 20 gal / 1000 gal acid Corrosion Inhibitor, Use at moderate to high temperatures (300°F +) Similar chemistry to CI-14, Environmental Rating of "C" for North Sea Intensifier required over 200°F 1-20 gals per 1000 gals of acid Corrosion Inhibitor, Use at moderate to high temperatures (300°F +) Similar chemistry to CI-14, Environmental Rating of "C" for North Sea Intensifier required over 200°F 1-20 gals per 1000 gals of acid Do not store over 100°F, limited shelf life. Acid corrosion inhibitor for high temperatures to 400°F (205°C), and chrome steels Use with chrome steel above 300°F (150°C), and all steel above 350°F (175°C) CI-30 contains no EPA priority pollutants. Used with Hy Temp 400 5 to 20 gal / 1000 gal acid

Inhibitor - Brine Natri-Hib 7008

Saltrol 2

Salt inhibitor is a patented water soluble formulation. (Chemical Services) Will prevent salt deposition in producing wells over a wide range of temperature and pressures. Minimizes wash out in salt formations during drilling. Batch mixed Salt inhibitor is a patented water soluble formulation. Will prevent salt deposition in producing wells over a wide range of temperature and pressures. Minimizes wash out in salt formations during drilling. Batch mixed

Inhibitor - Intensifier Hy Temp 382

Intensifier for CI-25 acid corrosion inhibitor, for inorganic and organic acids Use with CI-25 at 275-325°F (135-175°C) for chrome steel Must be added to prepared acid, do not filter 2 to 50 gal / 1000 gal acid

Inhibitor - Sulfide HS-4

HS-22

Non-ionic, Hydrogen sulfide complexer, (North Sea Usage) Forms stable complex with sulfide ions in sour wells Prevents precipitation of Iron sulfide and sulfide cracking of tubulars 1 to 10 gal / 1000 gal acid Organic corrosion inhibitor for H2S and CO2 environments Corrosion inhibition in underbalance coil tubing drilling.

Iron Control Ferro Free™

Ferrotrol 1000

Ferrotrol 200

Ferrotrol 210


Environmentally friendly, biodegradable used to provide neutral pH derusting solutions Lowers surface tension, leaves formations water-wet upon contact Used to make RustBuster solutions of 6 and 12 Acid chelating agent, may be used in all acids, including HCl/HF Least effective iron control agent, solubility in 15% HCl limited to 89 lb / 1000 gal Maximum chelation of 1500 ppm total iron from ambient to 350°F (175°C) 50 to 90 lb / 1000 gal HCl acid. Do not use with HF acid. Ferric iron reducing agent Very soluble, effective to 350°F (175°C), same chemistry as Ferrotrol 210 Helps prevent asphaltene sludging, will degrade in strong acid and with time 10 to 100 lb / 1000 gal acid, do not use with HF or HCl > 20% Ferric iron reducing agent, for HCl/HF and HCl <20% Very soluble, effective to 350°F (175°C), same chemistry as Ferrotrol 200 Helps prevent asphaltene sludging, will degrade in strong acid and with time 8 to 80 lb / 1000 gal acid


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Iron Control Ferrotrol 210C

Ferrotrol 260L

Ferrotrol 262L

Ferrotrol 280L

Ferrotrol 300

Ferrotrol 300L

Ferrotrol 700

Ferrotrol 800

Ferrotrol 800L

Ferrotrol 810

Ferrotrol 900

Ferrotrol 900L

RustBuster™ 12

RustBuster™ 6


Ferric iron reducing agent, for HCl/HF and HCl <20% Very soluble, effective to 350°F (175°C), same chemistry as Ferrotrol 200 Helps prevent asphaltene sludging, will degrade in strong acid and with time 8 to 80 lb / 1000 gal acid Ferric iron reducing agent Effective in up to 28% Acid, HF acids, and spent acid Expensive, but small quantities are required 2.0 to 15 gal / 1000 gal Ferric iron reducing agent Effective in up to 28% Acid, HF acids, and spent acid Expensive, but small quantities are required 4.0 to 15 gal / 1000 gal Proprietary ferric iron reducing agent Reduces up to 10,000 ppm ferric iron, effective in spent and live acids Limited to 20% or less HCl and 12%/3% HCl/HF 2 to 16 gal / 1000 gal acid Anhydrous citric acid iron chelating agent Effective in all acids, economical and efficient, use with acetic acid Loses effectiveness with temperature, may form precipitant without sufficient iron 25 to 250 lb / 1000 gal acid 29.45 ppt will Liquid citric acid iron chelating agent, 1 gal = 5 lb Citric acid Effective in all acids, economical and efficient, use with acetic acid Loses effectiveness with temperature, may form precipitant without sufficient iron 5 to 50 gal / 1000 gal acid Acid chelating agent, may be used in all acids, including HCl/HF Least effective, hard to dissolve, solubility in 15% HCl limited to 68 lb / 1000 gal Maximum chelation of 1500 ppm total iron from ambient to 350°F (175°C) 40 to 70 lb / 1000 gal HCl acid. Do not use with HF acid. Acid chelating agent, may be used in all acids, including HCl/HF Effective to above 350°F (175°C), no formation of insoluble precipitants Do not use with HF acid, solubility limited to 50 lb / 1000 gal 28% HCl 25 to 350 lb / 1000 gal acid Acid chelating agent, may be used in all acids, including HCl/HF Effective to above 350°F (175°C), no formation of insoluble precipitants Do not use with HF acid, solubility limited to 10 gal / 1000 gal 28% HCl 5 to 75 gal / 1000 gal acid Acid chelating agent, may be used in all acids, including HCl/HF Effective to above 350°F (175°C), no formation of insoluble precipitants Little solubility in water limited solubility in weak acids 25 to 350 lb / 1000 gal acid EDTA chelation agent, same chemistry as Ferrotrol 1000, 700, and 900L Least effective iron control agent, solubility in 15% HCl limited to 100 lb / 1000 gal Maximum chelation of 1500 ppm total iron from ambient to 350°F (175°C) 70 to 100 lb / 1000 gal HCl acid. Do not use with HF acid. Acid chelating agent, may be used in all acids, including HCl/HF Least effective iron control agent, solubility in 15% HCl limited to 23 gal / 1000 gal Maximum chelation of 1500 ppm total iron from ambient to 350°F (175°C) 15 to 20 gal / 1000 gal HCl acid. Do not use with HF acid. Environmentally friendly, derusting and pickling solution Neutral pH, with fresh water or light brines. Volume based on contact time and amount of iron dissolved. Environmentally friendly, derusting and pickling solution Neutral pH, with fresh water or light brines. Volume based on contact time and amount of iron dissolved.


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Miscellaneous Ammonium Bifluoride

Ammonium Fluoride

Pentafax 2

Ammonium Bifluoride intensifier for HCl / HF acid systems Used to prepare acid systems up to 15% HCl and 6% HF Corrosive crystalline solid 100 to 1000 lb per 1000 gal mud acid Calcium Carbonate, Calcite, limestone, dolomite Sodium or potassium compound Ammonium fluoride intensifier for HCl / HF acid systems Used to prepare acid systems up to 15% HCl and 4% HF Non-corrosive liquid 24 to 210 gal per 1000 gal mud acid Decomposes to ammonia gas, ammonium Bifluoride, hydrogen fluoride Unique blend of micellar solvents, emulsifiers, and surfactants for Pentol systems Stabilizes the acid and solvent blend Disrupt emulsion blocks, reduce interfacial fluid surface tension 20 gpt to 40 gpt

Non-Emulsifier NE-110W

NE-118

NE-13

NE-23

NE-940

Anionic surfactant for water, acid, oil, or brine De-emulsifier / Mutual Solvent / Emulsion Water Block Breaker Water wets sandstone 1 to 5 gal / 1000 gal Non-ionic surfactant for water, acid, oil, or brine Non Emulsifier and Emulsion Block Breaker Water wets Sandstone and carbonates 1 to 5 gal / 1000 gal Cationic and non-ionic de-emulsifier for acid or oil Helps prevent sludging of oils Recommended for use in carbonate formations 0.5 to 5 gal / 1000 gal acid Anti-sludge preventer and non-emulsifier in acid stimulation treatments Helps prevent the occurrence of asphaltine sludges Designed for use in carbonate formations Usage range 1-8 gals/1000 gals of acid. Non-ionic de-emulsifier for acid, water, or brine De-emulsifier and wetting agent Water wets sandstone and carbonates 1 to 5 gal / 1000 gal, Unconds. Sandstone w/mutual solvent 0.5-3.0% Cons. Sand 0.1-1.0%, Uncons. Sand 0.5-2.0%

Paraffin Dispersant Envirosol-XS

Paravan 25

Paravan D


Water-based solvent system to remove asphaltene and wax deposits. Water-wets formation after treatment Biodegradable Contains 50 gals / 1000 gals Paravan 25 Biodegradable, essentially non-toxic, high boiling alternative to solvents. Terpene based solvent blended with surfactants. Contains no petroleum solvents, heavy metals or chlorine. Used full strength or diluted 5 vol% in water for EnviroSol-XS Strong Mineral Acids Strong Oxidizing Agents Formation wash for crude oil, paraffin, and asphaltene deposits Surfactants prevent emulsions and lower surface tension Contains acetic acid to dissolve scales, strong wetting action with mutual solvent Varies with application


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Paraffin Dispersant Paravan E

Paravan F

Formation wash for crude oil, paraffin, and asphaltene deposits Surfactants prevent emulsions and lower surface tension Contains acetic acid to dissolve scales Varies with application Formation wash or acid preflush for crude oil, paraffin, and asphaltene deposits Surfactants prevent emulsions and lower surface tension Contains mutual solvent to maximize relative permeability Varies with application

Salt Sodium Chloride, Fine

Sodium Chloride, 100 mesh It is used to protect against clay swelling, and for formation compatibility Accelerator for cement slurries, from 1-12% BWOW, neutral 12-18%, retards above 18% BWOW Varies with application Tends to adversely affect fluid loss additives for cement

Scale Solvent Gyp-Aid II Gypsol 2

Gypsum converter and disintegrator 10 - 50% in Water Water-based Calcium Sulfate scale converter Contains de-oiling surfactant

Solvent AE-Aromatic Diesel Fuel Kerosene, Diesel 1 MS-16

Naphtha, aromatic hiflash

Techni-Clean 4550

Techni-Clean 4555

US-2

US-40


Aromatic solvent for Pentol systems Varies from 80 gpt to 310 gpt Diesel solvent C9-C20 hydrocarbon mix Kerosene (Diesel #1) Non-ionic mutual solvent, de-emulsifier, water block breaker, water wetter Use in acid to aid removal of near wellbore skin damage, soluble in water 5% by volume in acid and brines Aromatic naphtha solvent Used as hydrocarbon solvent and as a treatment fluid base Flash point >100°F, variable composition depending on source Varies with application Blend of solvents and surfactants Effective at dissolving and dispersing pipe dope and oil base mud Environmentally acceptable, contains no aromatic, terpene solvents 250 gallons ahead of KCl brine, reverse out and repeat if necessary. Blend of solvents and surfactants, creates clear microemulsion Effective at removal of mud, pipe dope, oil, barite and other solids Environmentally acceptable, contains no aromatic, terpene solvents 5-6% solution in water or brine Designed to complement the Techni-Clean 4550 Mutual solvent for acidizing, requires lower loadings than Inflo-40 Reduces adsorption of surfactants and inhibitors from acid by keeping them in solution Soluble in oil and water, water wets, helps prevents emulsions Use at 5 vol% in acid Compatible with Spectra Frac G Non-ionic mutual solvent, water wets, helps prevents emulsions Reduces adsorption of surfactants and inhibitors from acid by keeping them in solution Soluble in water and oil, use to 250°F (120°C) Normally used at 2-25 gals/1000 gals of acid 5-10% by volume with HCL-HF blends for sandstone formations.


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Solvent Xylene

Aromatic solvent for oilfield chemicals Used to remove paraffin and asphalt deposits from wellbore tubulars and formation face Greater dissolving power for asphaltic material as compared to diesel/kerosene Generally used at 150-500 gals/1000 gals. Paraffin remover and solvent. Tendency to Oil-wet carbonate rocks Strong oxidizers or hydrogen peroxide

Surface Tension Flo-Back 20™

Flo-Back 30™

Inflo-102

Inflo-150

LT-21

LT-32

Non-Ionic surfactant for fracturing and matrix acidizing Wetting agent, fluid recovery surfactant Applicable to gas reservoirs, enhances load water recovery 1 to 5 gal / 1000 gal Emulsion problems in presence of condensate Use with NE-940, NE-118 Zwetter-ionic surfactant for fluid recovery Effective up 300°F 1 to 5 gals per 1000 gals Cationic and nonionic surfactants for water based fracturing fluids De-emulsifier, surface tension reducer, fluid recovery surfactant, Water wets sandstone and carbonates, Can be used in gas reservoirs that produce condensate 0.5 to 5 gal / 1000 gal Nonionic surfactant for water based fracturing fluids Contains fluorosurfactant surface tension reducer for fluid recovery Water wets both sandstone and carbonates 0.5 to 5 gal / 1000 gal Emulsion problems in presence of condensate Use with NE-940, NE-118 Non-ionic silt-suspender for water, acid, and brines Acid retarder / silt suspender / wetting agent Water wets sandstone and carbonates 1 to 5 gal / 1000 gal May stabilize acid/brine with oil. Use NE-940 or NE-118 to help break. Non-ionic Surfactant for water, acid, oil, or brine Surface Tension Reducer / Microemulsifier / Penetrant / Paraffin Dispersant Used for perf breakdown, and removal of near wellbore damage 1 to 5 gal / 1000 gal

Surfactant S-150

S-301

S-351

S-400


Blend of amphoteric and non-ionic surfactants Low cost water wetting surfactant Water wets sandstone and carbonates from water and brine 1 to 20 gal / 1000 gal Anionic and non-ionic surfactant for water and acid Oil dispersant / penetrant / water wetter / de-emulsifier Normally used on sandstone 2 to 50 gal / 1000 gal Multi-purpose surfactant, flow back and non-emulsifier Non-ionic surfactant for water and acid Strong water-wetter aids in fluid recovery Normal usage 0.5-2 gpt of fluid. Nonionic surfactant for water, brines, acid, and oil Detergent / dispersant / foamer / emulsifier Water wets sandstone and oil wets carbonates 5 to 50 gal / 1000 gal Temperature limit 150°F


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Water Control AquaCon™ Concentrate

AquaCon™ HP

AquaCon™ System

Aquatrol I

Aquatrol I Concentrate

SAF Mark II

SAF Mark II System

SAF Mark III SAF Mark III System

WCB-1


Permeability modifier to control water production Controls by hydrophilic action 1 to 6 % in water Permeability modifier to control water production Controls by hydrophilic action 1 to 6 % in water Permeability modifier to control water production Controls by hydrophilic action 2 to 6 % in water. Water control system, mixed with suitable clean brine (normally 2% KCl) Hydrophilic -- Increases Friction pressure of water flowing in formation Thus reducing formation water production with little or no effect on reservoir oil production Use from 60°F to 250°F (16°C to 121°C) Used to formulate Aquatrol I water control system 1 to 8 % by volume, determined by formation permeability Incompatible with strong acids. Concentrate for SAF Mark II water control system Used at 22%(vol) in Water 1 drum SAF Mark II in 195, 295, or 445 gal of water Selective water control system The reaction with the dissolved salts in the formation brine causes a sticky precipitate SAF Mk II has also been used successfully in loss circulation problems. 1 drum SAF Mark II in 195, 295, or 445 gal of water for mD > 100 use 195 gal water, for mD 10-100 use 295 gal water, for mD <10 use 445 gal water Maximum temp 300°F (149°C). Formation brines must contain a minimum of 500 ppm divalent ions. Concentrate for SAF Mark III water control system Mixed at 11% with Water Non-selective permanent water control system Reacts with multivalent ions to form a highly cohesive seal Has also been used successfully in severe loss circulation problems. Maximum temp 350°F (177°C). For use in oil wells only. Mix water must be basic (pH 8 -9.5), Acidic conditions will cause Coagulation Aids in adhesion of AquaCon polymer to formations Mobilizes siliceous fines in the formation through siloxane covalent bonds 2-5 gpt


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Anti-Foam FP-11

FP-12L

FP-13L

FP-6L

Powdered de-foamer for cement slurries Surfactant on silicon dioxide Produces effective density control by reducing problems associated with air entrainment 0.1 to 0.4 % by BWOC Is not effective at controlling surface foam or with latex slurries Silicon, oil based emulsion used as a cement de-foamer Very effective at controlling air entrainment and surface foam Effective in temperatures to 500°F (260°C) 0.02 to 0.20 gal / sack of cement 0.02 to 0.15 gal /bbl of spacer Caution is advised when storing this additive since temperature above 150°F or below 32°F can cause the emulsion to break Oil based, water dispersible cement de-foamer Very effective minimizing air entrapment Prevents foaming tendencies of latex systems 0.005 - 0.02 gal / sacks Inexpensive liquid cement defoamer used to control surface foam Surfactant based cement defoamer 0.05 gal / sack Added to the mixing water in concentrations of 0.5 gallons per 10 barrels. Not effective in controlling air entrainment

Bonding BA-10

BA-10A

BA-11

BA-55

BA-55HT

BA-56


Gas migration control additive, stabilizes foamed cements High molecular weight polymer for use from 80-240°F (25-115°C) Primary application is as a component of other bonding and fluid loss additives 0.2 to 2 % BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31 Gas migration control additive, stabilizes foamed cements High molecular weight polymer for use from 80-240 F (25-115 C) Primary application is as a component of other bonding and fluid loss additives 0.2 to 2 % BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31 Used to control gas migration and as a fluid loss additive Provides free water and fluid loss control, stabilizes foamed cements Used at temperatures up to 350°F (175°C) 0.2 to 2.0% BWOC Do not use with borate retarders or CD-31 Not compatible with salt concentrations > 5 % Controls gas migration through polymeric means Improves bonding and reduces cement permeability Prevents gas migration, controls fluid loss and free fluid, effective to 240°F (115°C) 0.8 to 2.0% BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31 Prevents gas migration, controls fluid loss and free fluid through polymeric means Improves bonding and reduces cement permeability Controls fluid loss, stops gas migration, effective to 340°F (171°C) 1.0 to 2.5% BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31 Controls gas migration through polymeric means Improves bonding and reduces cement permeability Prevents gas migration, controls fluid loss and free fluid, effective to 240°F (115°C) 0.8 to 2.0% BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Bonding BA-56HT

BA-58

BA-59

BA-61

BA-90

BA-9L

CSE

CSE-2

EC-1

EC-2


Prevents gas migration, controls fluid loss and free fluid through polymeric means Improves bonding and reduces cement permeability Controls fluid loss, stops gas migration, effective to 340°F (171°C) 1.0 to 2.5% BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31 Improves cement bonding and compressive strength Free flowing siliceous powder and high molecular weight resins Use in dense slurries, 15.6 lb / gal and above, temperatures to 350°F 1.5 to 15% BWOC Improves cement bonding and compressive strength Used at temperatures up to 300°F (148 °C) BHCT. Patent # 4,332,619 0.2- 0.25% by weight of cement up to 300 °F (148 °C). Do not circulate to surface Do not batch mix Controls gas migration through the formation of compressible cement Improves bonding and minimizes gas migration Use to 300°F (148°C), generates a timed delayed hydrogen gas internally 1 to 1.5% BWOC Do not circulate to surface Do not batch mix Improves cement bonding and compressive strength Free flowing siliceous powder for use at all temperature ranges For use in low density slurries, 14.5 lb / gal and below 4 to 25% BWOC Used at temperatures up to 300 °F (148 °C) to improve bonding in cement slurries. The water requirement varies due to weight requirements. Liquid suspension for BA-10 used to control gas migration and as a fluid loss additive Provides free water and fluid loss control, stabilizes foamed cements Effective at temperatures to 240°F (115°F) 15 - 60 gal / 100 sacks, 1.5 to 2% BWOC Not compatible with slurries containing Bentonite or more than 3% salt Do not use with borate retarders or CD-31 Improves cement bonding and compressive strength Free flowing siliceous powder for use at all temperature ranges For use in low density slurries, 15.6 lb / gal and below 10 to 25% BWOC Improves cement bonding and compressive strength Free flowing siliceous powder for use at all temperature ranges For use in low density slurries, 15.6 lb / gal and below 10 to 25% BWOC Not the same as CSE or BA-90. Hydrofluoric acid, powerful oxidizing agents Cement expansion additive for low to moderate temperatures Provides controlled expansion of Portland cements Can be used at any temperature below 200°F (93°C) 0.1 to 1.0% BWOC Will require additional retarder in most cement slurries Cement expansion additive for high temperatures Provides controlled expansion of Portland cements Can be used at any temperature above 200°F (93°C) 0.1 to 1.0% BWOC Will require additional retarder in most cement slurries


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Cement Cement ASTM Type I

Cement Class A

Cement Class B

Cement Class C

Cement Class G

Cement Class H

Cement Premium H

Lite-Wate T

Corresponds to API Class A, Normally mixing density 15.2 to 15.6 ppg Used at BHCT less than 110°F (43.3°C) Provides good early compressive strength development at low temperatures Only Manufactured as ordinary cement, not sulfate resistant Cement ASTM Type III Corresponds to API Class C, Normally mixing density 14.8 ppg Used at BHCT less than 120°F (48.8°C), but can be modified for higher temperatures Provides good early compressive strength development at low temperatures Is used from surface to 6000' Can be modified with specialty products to meet well criteria Normally mixed at 15.6 ppg Available in ordinary and moderate sulfate resistance Normally used from surface to 6000' Can be modified for most well conditions Normally mixed at 15.6 ppg Available in moderate and high sulfate resistance Normally used from surface to 6000' Is considered a high early strength cement Normally mixed at 14.8 ppg Available in ordinary, moderate and high sulfate resistance Intended for use from surface to 8000' as a basic cement Can be modified with specialty products to meet well criteria Normally mixed at 15.8 ppg Available in moderate and high sulfate resistance Intended for use from surface to 8000' as a basic cement Can be modified with specialty products to meet well criteria Normally mixed from 15.6 to 16.4 ppg Class H cement Joppa Plant Cement Premium II Normally used from surface to 6000', basically Type II Cement Can be modified for most well conditions Normally mixed at 15.6 ppg Manufactured light-weight cement, Normally mixed from 12.5 to 14.5 ppg without modifications Resist strength retrogression up to 300°F w/o additional silica Compatible with all cement additives Only available through TXI cement in Dallas, Texas

CMT Extender Attapulgite Clay

Bentonite

Fly Ash (Pozzolan)

Fly Ash L (Pozzolan L)


Cement extender and aid for control free fluid Additive to spacers Hydrates better in high salt environments than Bentonite Can cause rapid gellation or false sets in cements 0.2 to 2.0 % Economical cement extender Can be prehydrated in mix water (2% prehydrated equivalent to 8% dry) Will help control fluid loss Will cause slight acceleration at temperatures above 110 F 2.0 to 16.0 % Artificial Pozzolan cement extender API Spec 10, Fly Ash available as a Type F or Type C Used as a ratio to cement to make 1 cuft The first number in the ratio refers to the fly Ash (exp. 35:65 - 35% fly ash: 65% Cement) Bulk density and specific gravity of Fly Ash can very widely Artificial Pozzolan cement extender, lower bulk weight than existing Fly Ash API Spec 10, Fly Ash available as a Type F or Type C Used as a ratio to cement to make 1 cuft The first number in the ratio refers to the fly Ash (exp. 35:65 - 35% fly ash: 65% Cement) Bulk density and specific gravity of Fly Ash can very widely


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS CMT Extender LW-6

LW-7-10 LW-7-4 LW-7-6 Sodium Metasilicate

Sodium Silicate, Liquid

Ceramic microsphere cement extender Can be used to extend cement slurries to densities as low as 7.0 ppg 10 to 130 % BWOC 5 to 20 % of the spheres can collapse at pressures of 6000 psi. Glass bubbles 10,000 psi burst Minimum fractional survival rate at maximum pressure is 80% Glass bubbles 4000 psi burst Minimum fractional survival rate at maximum pressure is 80% Glass bubbles 6000 psi burst Minimum fractional survival rate at maximum pressure is 80% Dry cement extender Used to obtain densities from 14.5 to 11.5 ppg Accelerates thickening time and increase strength development Handle with caution to prevent burns do to the caustic nature of the SMS 0.5 to 4 %BWOC At concentration > 3% and temperatures > 100°F use R-17 (Zirconium Borate) as retarder Liquid cement extender Used to obtain densities from 14.5 to 11.5 ppg Accelerates thickening time and increase strength development 0.2 to 0.8 gal/sack 23 ghs = 1.0% SMS, 46 ghs = 2.0% SMS, 68 ghs = 3.0% SMS Solid content 38.3 % BWOW (4.066 ppg Sodium metasilicate (A-2)) Sodium Silicate slurries may require special retarders. (R-17)

Dispersant CD(+)500

CD-31

CD-31L

CD-32

CD-32L

CD-33

CD-33L


High temperature dispersant for cement slurries. Aids in fluid loss control and can serve as a retarder. Primarily used in OB-1 spacer system. Solid cement dispersant and turbulent flow inducer Work synergistically with fluid loss additives Sodium Salt of a Highly Polymerrized alkyl napthalene Sulfonic Acid 0.2 to 0.75 % BWOC When used at greater than a 1:1 ratio with HEC can cause viscosity increase Do not used with BA-10 or materials containing BA-10 Liquid cement dispersant and turbulent flow inducer Work synergistically with fluid loss additives Aqueous Solution of Sodium Salt of a Highly Polymerrized alkyl napthalene Sulfonic Acid 0.05 to 0.2 gal / sack 3.24 lbs per gallon When used at greater than a 1:1 ratio with HEC can cause viscosity increase Do not use across producing intervals, to prevent damage Solid surfactant enhanced Napthalene Sulfonic Acid, cement dispersant and turbulent flow inducer Work synergistically with fluid loss additives Use to activate and disperse slurries containing BA-10 0.2 to 0.75 % BWOC Liquid cement dispersant and turbulent flow inducer Work synergistically with fluid loss additives Non-Foaming 0.05 to 0.2 gal / sack 3.24 lbs per gallon Solid cement dispersant and turbulent flow inducer Work synergistically with fluid loss additives Non-Foaming 0.2 to 0.75 % BWOC Liquid cement dispersant and turbulent flow inducer Work synergistically with fluid loss additives Non-Foaming 0.05 to 0.2 gal / sack 3.24 lbs per gallon


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Dispersant Sodium Gluconate

Dispersant for Magna Plus Cement Sequestering agent for divalent and trivalent metal cations especially in a high pH environment.

Fluid Loss - Cement Diacel LWL

FL-25

FL-52

FL-52A

FL-62

FL-63

FL-66

FL-66L

FL-67L

FLR-1

FLR-1L


Cellulose base cement fluid loss agent, retarder, and spacer additive Effective retarder from 200°F(93°C) to 250°F (121°C) Needs accelerator below 200°F (95°C), salt compatible 0.3 to 1.5 % BWOC General purpose cement fluid loss agent for primary and remedial cementing Effective to 300°F (150°C) in fresh or salt water up to 18% Low cost, custom blended at the district - (part of the fluid loss hybrids) 0.4 to 2% BWOC Polymeric cement fluid loss agent for low to medium density extended slurries For use in fresh or saturated salt water to 300°F (150°C), provides free water control Will increase slurry viscosity 0.2 to 1% BWOC Polymeric cement fluid loss agent for low to medium density extended slurries For use in fresh or saturated salt water to 300°F (150°C), provides free water control Will increase slurry viscosity(Slightly different from FL-52, limited supply) 0.2 to 1% BWOC Cement fluid loss agent for primary and remedial cementing to 240°F (115 C) Ultra-low fluid loss, minimal retardation, provides turbulent flow for liner cementing Low cost, low temperature fluid loss additive, custom blended at the district 0.4 to 2.5% BWOC Do not use with borates or CD-31 Not compatible with slurries containing Bentonite or salt > 3 % Polymeric cement fluid loss and gas migration control agent to 350°F (175 C) Non-retarding with very low fluid loss, 2% calcium chloride tolerance Stabilizes BA-86L, may extend temperature range of FL-62 and BA-56 0.2 to 1% BWOC Has a dispersing action, which may cause free fluid or settling problems Polymeric cement fluid loss and gas migration control agent to 350°F (175 C) Non-retarding with very low fluid loss, 2% calcium chloride tolerance Stabilizes BA-86L, may extend temperature range of FL-62 and BA-56 0.2 to 1% BWOC Has a dispersing action, which may cause free fluid or settling problems Liquid cement fluid loss and gas migration control agent to 350°F (175 C) Non-retarding with very low fluid loss, 2% calcium chloride tolerance Stabilizes BA-86L, may extend temperature range of FL-62 and BA-56 0.2 to 1 gps Avoid contact with rust for prolonged periods, will crosslink Has a dispersing action, which may cause free fluid or settling problems Liquid cement fluid loss and gas migration control agent to 350°F (175 C) Non-retarding with very low fluid loss, 2% calcium chloride tolerance Stabilizes BA-86L, may extend temperature range of FL-62 and BA-56 0.2 to 1 gps Avoid contact with rust for prolonged periods, will crosslink Has a dispersing action, which may cause free fluid or settling problems Retarding, non-viscosifying fluid loss additive for high temperature cement slurries Particularly suited for use with coil tubing and/or close tolerance liner cementing. Can lower retarder loadings in some slurries. Retarding, non-viscosifying liquid fluid loss additive for high temperature cement slurries Particularly suited for use with coil tubing and/or close tolerance liner cementing. Can lower retarder loadings in some slurries.


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Liquid Stone LSA-1 LSA-2

Accelerator for Liquid Stone 0.1 to 0.15 gal/sack of cement Accelerator for Liquid Stone, Calcium Chloride liquid

LSA-3

Accelerator for Liquid Stone

LSA-5

Accelerator for Liquid Stone Accelerates thickening time and increase strength development Handle with caution to prevent burns do to the caustic nature of the SMS 0.5 to 4 %BWOC Plastizer for Liquid Stone 0.04 to 0.06 gal/sack of cement Retarder for Liquid Stone 0.08 to 0.2 gals/sack of cement Suspending agent for Liquid Stone 0.1 to 0.15 lbs/sack of cement Suspending agent for Liquid Stone 0.1 to 0.15 lbs/sack of cement

LSP-1 LSR-1 LSS-1 LSS-2

Lost Circulation Cello-Flake

Flow Guard L

Flow Guard LC

Kol Seal

LCM-1

Magne Plus Cement

Magne Plus LT Cement

Max Seal


Cellophane flake lost circulation agent Lost Circulation agent for cement slurries 1/4 lb/sack of cement Liquid permanent loss circulation agent for non-productive thief zones Forms viscous plug when contacted by Calcium rich fluid Normally 20 to 40 bbls w/brine spacers ahead and behind Do not use across producing intervals, to prevent damage Is non reversible Liquid permanent loss circulation agent for non-productive thief zones Forms viscous plug when contacted by Calcium rich fluid Concentrated Normally 20 to 40 bbls w/brine spacers ahead and behind Solid content 38.3 % BWOW (4.066 ppg Sodium metasilicate (A-2)) Do not use across producing intervals, to prevent damage Is non reversible Coarse ground coal lost circulation agent. Can be used as a extender with higher compressive strengths than gilsonite. Can work as a scouring agent of formation mud cake. 2 to 10 ppb of slurry Particulate asphaltene bridging material used to control lost circulation Can be used to extend slurry density w/o additional water Used at temperatures up to 300°F, will soften at 240°F Recommended usage 10-15 lbs/sack, Usable range 5-50 lbs/sack Settable lost circulation control system for temperatures from 140°F (60°C) to 225°F (157°C) Acid soluble cement Variable uses to control lost circulation, temporary plug, sealing bridge plug, stabilizer formations, etc. Normally mixed at 13.5 ppg Must use special products to disperse and/or retard Settable lost circulation control system for temperatures < 140°F ( 60°C ) Acid soluble cement Variable uses to control lost circulation, temporary plug, sealing bridge plug, stabilizer formations, etc. Normally mixed at 13.5 ppg Must use special products to disperse and/or retard Low density, shredded rubber, fibrous material for use as lost circulation material Softness allows pressure deformation for improved sealing. Works best in lost circulation caused by small fractures 2 to 10 ppb of slurry


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Lost Circulation Mud-Save F

Mud-Save M

Perfalite

Perlite

PolyFX B

PolyFX BM

PolyFX D

PolyFX DM

Surebond I

Surebond II

Surebond III


Lost circulation agent, Synthetic Rubber Material is not readily available, moving to delete list Same material as Mudsave M 499507 2 to 10 ppb of slurry Fine Material Lost circulation agent for mud, Coarse material Material is not readily available, moving to delete list Same material as Mudsave F 499506 2 to 10 ppb of slurry Lost circulation agent Perlite (California only) Used as a insulator for geothermal or steam injection wells 1 to 2 sacks per sack of cement Perlite weighs 8 to 10 lbs per cuft Pressure compresses the bead, so down hole pressure is higher than surface Perlite cement extender Perlite (California only) Used as a insulator for geothermal or steam injection wells 2 to 2 sacks per sack of cement Perlite weighs 8 to 10 lbs per cuft Pressure compresses the bead, so down hole pressure is higher than surface Forms gelatinous mass upon contact with water Cures lost circulation problem in productive or non-productive intervals Mixture of polymers, crosslinkers and surfactant. Determine rate of loss, capacity of hole Water Forms gelatinous mass upon contact with water Cures lost circulation problem in productive or non-productive intervals Mixture of polymers, crosslinkers and surfactant. Determine rate of loss, capacity of hole Water Forms gelatinous mass upon contact with water Cures lost circulation problem in productive or non-productive intervals Mixture of polymers, crosslinkers and surfactant. Determine rate of loss, capacity of hole Water Forms gelatinous mass upon contact with water Cures lost circulation problem in productive or non-productive intervals Mixture of polymers, crosslinkers and surfactant. Determine rate of loss, capacity of hole Water Water control and Lost circulation system Water wets pipe and formation, helps enhance bonding Controls fluid loss to fractured formations Minimum of 10 barrels Water control and Lost circulation system Water wets pipe and formation, helps enhance bonding Controls fluid loss to fractured formations Minimum of 10 barrels Water control and Lost circulation system Water wets pipe and formation, helps enhance bonding Controls fluid loss to fractured formations Minimum of 10 barrels


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Retarder Granular Sugar

R-18

R-21

R-21L

R-3

R-7

R-8

R-8L

SR-31L

Retarder for cement Used primarily to prevent the hydration of cement around BOP's or in transports 10 to 20 lbs per bbl of cement Difficult to control retardation Not used in primary secondary cement jobs Retarder for thixotropic and sodium metasilicate extended slurries Effective to 240°F (115°C), use for Thixofil, Sureplug, Lightweight, and Class H slurries Reduces gelation problems associated with some Portland cements as compared to other retarders 0.1 to 1.0 % BWOC Incompatible with BA-10, BA-56, and FL-62 Cement retarder for low to medium temperatures. Effective to 240°F (115°C) 0.1 to 1.0% BWOC Not for use with sodium metasilicate extended slurries Liquid cement retarder for low to medium temperatures. Effective to 240°F (115°C), highly soluble, add to mix water 0.2 to 4 gps 4.32 lbs of solid per gallon Not for use with sodium metasilicate extended slurries Low temperature, solid, non-dispersing cement retarder, may be dissolved in water Effective from 120-240°F (50-115°C) 0.1 to 1.0% BWOC May cause gellation in low C3A cement (i.e. Class C) Not for high Bentonite or high Bentonite/high salt slurries Cold Set cement retarder Used for Cold set systems I, II, and III Also called Cold Set Retarder 0.1 to 0.2% BWOC High temperature solid cement retarder Effective from 200-400°F (95-205°C), concentration sensitive below 300°F (150°C) Mild dispersant 0.1 to 2.5% BWOC High temperature liquid cement retarder, can be added to mix water Effective from 200-400°F (95-205°C), concentration sensitive below 300°F (150°C) Foaming properties, acts as dispersant and may contribute to settling 0.02 to 0.5 gps 5.34 lbs of solid per gallon Synthetic retarder to control thickening time of oilwell cements from 200°F to 375°F Compatible with salts, will have some effect on slurry rheology at loadings of >0.4% Acts as a strong dispersant. 0.1 to 3.0 gps

Salt Calcium Chloride-L

Calcium Chloride Liquid Accelerates the set time on cement slurries Normally used at 20-60 ghs 1% Calcium Chloride= 27 ghs CaCl-Liquid

Sand S-8, Silica Flour


200 mesh silica Used to prevent strength retrogression at temperatures above 230°F 35% BWOC Require additional to water Add silica to obtain a 1:1 calcium to silica ratio


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Sand S-8C,Sand,100 mesh

Sand (Cement Applications)

100 Mesh Sand Used to prevent strength retrogression at temperatures above 230°F 35% BWOC Does not require additional water Add silica to obtain a 1:1 calcium to silica ratio Sand used in cement applications Used as an aggregate for setting cement plugs 10 to 20 lbs per sack Do not use as a prevention for strength retrogression

Spacer MCS-2

MCS-3

MCS-4

Mud-Clean I

Mud-Clean II

OB-1 Spacer

RSB Spacer

Ultra Flush HV

Ultra Flush II

Water based spacer for water based drilling muds Weighed from 9 to 20 lb / gal with barite, stable to 550°F (290°C) Turbulent flow spacer, water wetting, good rheology Varies with application Water based spacer for invert-emulsion drilling muds Weighed from 9 to 20 lb / gal with barite, stable to 550°F (290°C) Turbulent flow spacer, water wetting, good rheology Varies with application Water based spacer for all drilling muds Weighed from 9 to 20 lb / gal with barite, stable to 550°F (290°C) Turbulent flow spacer for on-the-fly mixing, water wetting, good rheology Varies with application Mud wash and spacer system Water-base, non-corrosive fluid Varies with application Mud wash and spacer system Water-base, non-corrosive fluid Varies with application Oil external phase emulsion spacer for hematite weighted oil external muds Compatible with salt saturated cement systems, stable to 350°F (175°C) Stable emulsion , weighed with hematite from 12 to 20 lb / gal Varies with application Oil and water emulsion based spacer for oil based muds Used as a spacer between mud and primary spacer system to prevent incompatibilities Use rig oil, weighed with barite to 19 lb / gal Varies with application Easy to mix turbulent flow spacer for water based drilling muds Weighed with barite to 20 lb / gal, stable to 350°F (175°C) Water wetting, simple to prepare, higher viscosity Varies with application Easy to mix turbulent flow spacer for water based drilling muds Weighed with barite to 20 lb / gal, stable to 350°F (175°C) Water wetting, simple to prepare Varies with application

Spacer Surfactant MCS-D

SS-2


Dry Surfactant for MCS cement spacer systems, Used in Alaska only Used in cement spacer systems to prevent mud incompatibility and improve bonding. OB-1 Emulsifier Emulsifier for OB-1 cement/mud spacer Stabilizes an oil external phase emulsion for hematite weighted oil muds. Varies with application Surfactant for cement spacer systems Strong water wetter, prevents mud incompatibility and promotes bonding Primary surfactant for MCS spacer systems, environmentally friendly, biodegradable 1 to 4 gal/bbl Ultra Flush II Concentrate Concentrate for Ultra-Flush II Water wetting, simple to prepare 0.25 to 0.4 gal / BBL


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Special Additive A-10, Gypsum

A-11,Lime

A-11A, Hydrated Lime

AEF-15 ASA-301

ASA-301L

KCl Free

MPA-1

MPA-3

Static Free

Enhances early compressive strength development in cement Thixotropic Cement Agent, Set time is typically one hour Seal off a lost circulation zone 1.0 to 12% BWOC Early compressive strength enhancer for cement Used to aid in cement free water control Functional at low to high temperatures ranges Early compressive strength enhancer for cement Used to aid in cement free water control Functional at low to high temperatures ranges Accelerator, Extender, Free Water Control, Used in West Coast region Reduces thickening time, Develops high early strength, Reduces WOC time. Free water and anti-settling agent control agent for cement Temperatures between 80 and 285°F (27°C and140°C) (BHCT) Normally used at concentrations between 0.05 - 0.2% (BWOC) Free water and anti-settling agent control agent for cement Temperatures between 80 and 285°F (27°C and140°C) (BHCT) Liquid suspension Concentrations between 1.0 - 4.0 ghs Non-accelerating clay control agent for cement slurries Minimize the damage of the sandstone type formation by cement filtrate Is an excellent aid for fluid loss control and is non-retarding. 1 gpt of mix water Fine white pozzolanic powders used to enhance various cement properties Functional at temperatures of 32°F to over 400°F Enhanced compressive, tensile, fleural strength development and reduced permeability Concentrations range from 1 to 30% BWOC Not recommended in USA at temperature above 180°F. Used to enhance slurries flexural strength Reduce brittleness Enhanced compressive, tensile, fleural strength development and reduced permeability Anti-static additive for proppants and dry cement Can be used to prevent cement packing during blending 0.05% by weight

Special Cement Cement Slag

Cold-Set

Foamed Cement

Liquid Stone


Cement slag for Blast Furnace Slurries Non-metallic product composed of silicates, aluminosilicates of calcium When mixed with drilling mud gives similar characteristics to Portland cements. Varies with application Not applicable to every well Low temperature cement slurries for permafrost cementing. Lower heat of hydration, reduces melting of the ice formation (Permafrost). Has good compressive strength and bonding properties. Varies with application Nitrogen foamed cement used for extremely low density slurries. Generates high compressive strengths as compared to other extenders at same density. Used across weak formations with low frac gradients where normal extenders can not. varies with application Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water.


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Special Cement Liquid Stone (bbls)

Liquid Stone Kit

Liquid Stone Kit Expansive

Liquid Stone RM 10.5



Lite-Set

Sure Fill

Sure Plug

Thixofil

Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water. Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water. Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water. Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water. Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water. Liquid cement suspension for remote, offshore or other unique wellsite locations. Permanently storable, pre-mixed cement slurry can be kept liquid on jobsite. Liquid activator added to re-initiates chemical hydration of the cement slurry. Varies with application Can not use Seawater used as a mix water. Ultra low density cement and very good compressive strengths. Designed to cement across weak formations where low hydrostatic pressures are required. Can be mixed from 9-15 lbs/gal. Varies with application Low temperature squeeze cement slurry Works in wells in which the loss of cement slurry to the formation is a problem. Varies with application Thixotropic cement plug slurry Works in wells in which the loss of cement slurry to the formation is a problem. Used for fast setting, high strength whip stock plugs at temperatures up to 350°F (177°C) BHCT Varies with application Low temperature thixotropic cement additive for squeezes and plugs Combination of two additives that varies in concentrations. Depending on thixotropic properties desired for the application

Weighting Material Barite

Hematite


weighting agent for spacers Bulk quantities Varies with density requirement Not normally recommended for cement, do to water requirement Cement and spacer weighting agent It is used to densify cement slurries up to 22 ppg Varies with density requirement Normally used at concentrations of 5% to 150% BWOC.


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS CF – Brine Calcium Chloride, 35% Potassium Chloride Brine Zinc Bromide Brine Zinc/Calcium Bromide HyCal I HyCal II HyCal II SB HyCal III

NoCal I

NoCal II

NoCal II SB

NoCal K

Calcium chloride brine 35% solution Solution Potassium Chloride 24% Solution Brine, 24% Solution 17 lb/gal Zinc Bromide solution used for heavy weight solutions 19.2 lb/gal Zinc/Calcium Bromide used for heavy weight clear solutions Calcium Chloride solution used for heavy weight solutions Density from 8.4-11.6 ppg Calcium Bromide + Calcium Chloride solution used for heavy weight solutions Density from 11.7-15.1 ppg Sodium Bromide solution used for heavy weight solutions Density from 8.4-15.3 ppg Zinc Bromide/Calcium Bromide/Calcium Chloride solution used for heavy weight solutions Mixture of the salts to provide density, cost savings and freeze protection. Density from 15.1-19.2 ppg Sodium Chloride solution used for heavy weight solutions Salts to provide density, cost savings and freeze protection. Density from 8.4-10.0 ppg Sodium Chloride + Sodium Bromide solution used for heavy weight solutions Mixture of salts to provide density, cost savings and freeze protection. Density from 10.1-12.4 ppg Sodium Bromide solution used for heavy weight solutions Salt to provide density, cost savings and freeze protection. Density from 8.4-12.7 ppg Potassium Chloride solution used for heavy weight solutions Salts to provide density, cost savings and freeze protection. Density from 8.4-9.7 ppg

CF - Defoamer Defoamer

Blended alcohol base compound Used to reduce and prevent entrained air in freshwater and brine fluids 5 gallons Defoamer per 250 bbls fluid.

CF - Displacement Well Wash 100

Well Wash 200

Well Wash 2000

Well Wash 2050

Well Wash 2100


Efficiently removes and disperses mud cake and residues Used in oil base mud displacements after the solvent package, Leaves water wet surface Most effective when used directly as a spacer without dilution Diluted 25:75 with fresh water or sea water before pumping as a spacer between water base mud and completion high flash naphtha distillate with exceptional oil and grease solvent properties Pickling operations prior to gravel packing to remove pipe dope Used neat or 50/50 dilution with diesel or mineral oil as a spacer Recommended for 5 minutes contact time as a pickling agent Ensure water wet pipe, the WELL WASH 200 spacer should be followed by WELL WASH 100 Removes oil based drilling mud and oily film residue from casing, pipe and exposed formation Leaves surfaces and solids Water Wet when flushed with water Flocculates oil mud solids, increasing particle size for effective removal during displacement Blend of surfactants to aid in the removal of mud, pipe dope, oil, sand, barite and other solids Forms a weak emulsion in water, creating a clear microemulsion water wetting, cleaning and dispersion characteristics Use full strength or diluted 50-60 gpt in water A synthetic and oil-based mud cleansing agent Blend of solvents and surfactants used to remove, dissolve and disperse drilling mud, residual invert emulsion mud, pipe dope and other oily film residue from wellbore tubulars


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS CF - Displacement Well Wash 3000

Well Wash 3500

Well Wash 400

Well Wash 4500

Synthetic and oil-based mud weighted-spacer surfactant Blend of solvents and surfactants used to remove, dissolve and disperse drilling mud, residual invert emulsion mud, pipe dope and other oily film residue from wellbore tubulars Synthetic and oil-based mud weighted-spacer surfactant Blend of solvents and surfactants used to remove, dissolve and disperse drilling mud, residual invert emulsion mud, pipe dope and other oily film residue from wellbore tubulars Pickling agent prior to perforating, stimulation, or gravel pack operations to remove pipe dope Used a displacement spacer, helps in the removal of iron rust and scale Used neat or 50/50 dilution with diesel or mineral oil as a displacement spacer Recommended for 5 minutes contact time as a pickling agent Displacement chemical for synthetic oil base muds Biodegradable, essentially non-toxic, terpene based solvent with surfactants Contains no petroleum solvents, heavy metals or chlorine Use full strength or diluted Avoid Strong mineral acids and Strong oxidizing agents

CF - Filter Media Diatomaceous Earth

Cement extender similar to pozzolan or a filter media for completion fluids Lowers cement density and increases slurry yield Has some strength retrogression properties above 230°F (110°C) 10%-40% BWOC

CF - Fluid Loss BD-Buff 54

Seal (Coarse)

Alkaline buffer designed for pH control and maintenance in brine-based drill-in fluids Controls the pH in an optimum 9-11 range Easily dispersed into brine systems of nearly any density or composition Recommended loadings of 1-5 pounds per barrel (ppb), with typical levels of 2-3 ppb Starch based crosslinked polymer specially designed for fluid loss control in brine-based drill-in fluids Increases low shear rate viscosity (LSRV) when used in conjunction with biopolymers such as Xanthan Used at temperatures of 300°F (higher in some cases), Recommended loadings of 3-8 pounds per barrel (ppb), with typical levels of 4-6 ppb. Most effective at higher temperatures (175°F-300°F may not fully disperse or hydrate at lower temperatures below 175°F Fluid Loss control coarse grade

Seal (Fine)

Fluid Loss control fine grade

Seal (Medium)

Fluid Loss control medium grade

BD-FL 44

CF - Inhibitor C-250

CB-250 HTI-2001

Hyperm NoMul C


Filming Amine Corrosion Inhibitor for Calcium Based Brine Designed for use in all non zinc workover/completion brines It is effective at temperatures up to 325 F 0.25 to 0.5 percent by volume in fresh water or completion fluids not recommended in zinc based fluids. Corrosion Inhibitors, surface active agents and biocides. Sulfur-free, amine-free corrosion inhibitor for use in brines Used in completion, workover and packer fluids up to 325°F (163°C) 2.5 gpt typically with 3.5 ppt of OS-8(Ferrotrol 200) required Special surfactants that are designed to inhibit the formation of completion fluid-in-oil (W/O) emulsions NoMul C is effective in calcium brines Excellent surface tension reduction enhances completion fluid recovery typically used at 0.1 to 1.0% by volume depending on crude characteristics


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS CF - Inhibitor Hyperm NoMul Z

Special surfactants that are designed to inhibit the formation of completion fluid-in-oil (W/O) emulsions NoMul Z is effective in zinc laden brines Excellent surface tension reduction enhances completion fluid recovery

CF - Oxygen Scavenger OS-8

Ferric iron reducing agent Very soluble, effective to 350°F (175°C), same chemistry as Ferrotrol 210 Helps prevent asphaltene sludging, will degrade in strong acid and with time 10 to 100 lb / 1000 gal acid, do not use with HF or HCl > 20%

CF - Packer Fluid InsulGel Super InsulGel

Packer fluid with insulating properties, minimize heat transfer from produced fluids. Wide variety of brine bases, broad range of densities, base fluid compositions and properties. Packer fluid with insulating properties, minimize heat transfer from produced fluids. Wide variety of brine bases, broad range of densities, base fluid compositions and properties.

CF - Scale Inhibitor SCB-100

Recommended for CaCO3, MgCO3, and CaSO4 scales and high temperature

CF - Surfactant OA-13

SS-10

Bleach concentrate 12% Sodium Hypochlorite Strong oxidizer 0.25 to 0.5 gal / 1000 gal Proprietary formulation designed to combine with hydrogen sulfide to form stable, water soluble reaction products Used in packer fluid inhibitor packages for carbon steel or 13 chrome tubulars

CF - Viscosifier BD-Vis 129

BD-Vis 130

Clean Plug HD

Clean Plug KF

DCE-1 DCP-1 HT Vis 508

HT Vis 708


High purity biopolymer specially designed for hole cleaning and solids suspension in brine-based drill-in fluids Designed to readily and fully disperse at pH ranges from 3 to 10 Easily dispersed into brine systems of nearly any density or composition Recommended loadings of 0.5-2.5 pounds per barrel (ppb), with typical levels of 1-2 ppb. High purity biopolymer specially designed for hole cleaning and solids suspension in brine-based drill-in fluids Designed to readily and fully disperse at pH ranges from 3 to 10 Easily dispersed into brine systems of nearly any density or composition Recommended loadings of 0.5-2.5 pounds per barrel (ppb), with typical levels of 1-2 ppb. Temporary crosslinked blocking gel Protect permeable zones from invasion by potentially damaging workover fluids. Can be mixed with heavy weight fluids. Calculate a 5 feet radial pore volume. Temporary crosslinked blocking gel Protect permeable zones from invasion by potentially damaging workover fluids. Can be mixed with heavy weight fluids. Calculate a 5 feet radial pore volume. Surfactant gel for Divert C Hygroscopic Cationic cellulosic polymer, used for stability of Divert C Viscofier for completion fluids High yield, low residue guar derivative for fresh water, seawater, and brines CMHPG (Carboxymethyl Hydroxyproply Guar) gelling agent Viscofier for Completion Fluids high viscosity chemically modified guar derivative Hydroxypropyl Guar, HPG


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS CF - Viscosifier Quick Vis

Ultra Vis


Non ionic, high molecular weight hydrophilic polymer viscosifier (HEC) Dispersed in a water miscible, polar organic solvent Readily disperses in all brine 1 to 4 gallons per barrel of completion fluid is recommended depending on viscosity desired. Highly concentrated (10.5 lbs per 5 gallons) HEC in organic potassium salt solution Easily disperses in fresh water, salt water and brines without shear 1.5 to 2.5 gallons per barrel


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Biocide Frac-Cide 1000

Frac-Cide 3

Magnacide 575

Sodium Hypochlorite,12%

X-Cide 207

X-Cide 5009

Dry biocide providing quick kill, bromide based Not effective in pH's above 8 Only licensed for use in Texas & New Mexico 3# per frac tank (20,000 gls) Retreat after 48 hours Liquid biocide, primary use in linear gel and fresh water, carbamate based Biocide with activity against algae, bacteria and fungi Control aerobic & anaerobic bacteria 1-2 pints per 100 bbls Liquid environmentally friendly biocide, Completely new class of antimicrobial chemistry Used to control aerobic, anaerobic, and sulfate reducing bacteria. Provides quick kill (1-2 hours) and long term (72 hours) protection 1 gal. per frac tank (20,000 gals) Bleach concentrate 12% Sodium Hypochlorite Strong oxidizer 0.25 to 0.5 gal / 1000 gal Solid granular biocide, Isothiazoline based Works best 24 hours after mixed, not recommended for quick kill of bacteria Broad spectrum control of slime-forming and sulfate reducing bacteria 6 lb / 500 BBL 0.3 lb / Mgal avoid pH >10 Dry biocide providing quick kill, bromide based Not effective in pH's above 8 3# per frac tank (20,000 gls)

Breaker - Oil GBO-5L

GBO-5LT

GBO-6

GBO-9L

GBO-9LT

RG-35 RG-38

Solid breaker in hydrocarbon slurry for use with Super Rheo Gel Effective at temperatures to 180°F (82°C) 0.5 to 10 gal / 1000 gal Solid breaker in hydrocarbon slurry for use with Super Rheo Gel Effective at temperatures to 180°F (82°C) Lower concentration for ease of pumping at low rates. 0.5 to 10 gal / 1000 gal Solid breaker for Super Rheo Gel systems Used as a 40% solution Active at temperatures from 150-300°F (65-150°C) 2 to 10 lb / 1000 gal Solid breaker in hydrocarbon slurry for use with Super Rheo Gel Effective at temperatures to 180°F (82°C) 2-4 gallons per thousand Solid breaker in hydrocarbon slurry for use with Super Rheo Gel Effective at temperatures to 180°F (82°C) Lower concentration for ease of pumping at low rates. 2-4 gallons per thousand Solid breaker used in RG-35SLR, GBO-5L, GBO-5LT Varies with application Hard burned material, slow release Solid breaker used in GBO-9L, GBO-9LT Varies with application

Breaker - Water Enzyme C


Cellulose specific enzyme breaker Use for GW-21 and GW-28 based polymer gels pH range 3-8, temperatures to 150°F (66°C) Varies with application


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Breaker - Water Enzyme C-HT

Enzyme G-I

Enzyme G-II

Enzyme G-III

Enzyme G-IV

Enzyme G-NE

Enzyme G-V

Enzyme G-VI

Enzyme G-VII

Enzyme S, GBW-16C

Enzyme X

GBW-12CD

GBW-14C

GBW-15C


Cellulose specific enzyme breaker for high temperatures Use for GW-21 and GW-28 based polymer gels pH range 3-8, temperatures from 140°F to 250°F (60-121°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-11, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Enzyme breaker for guar and guar derivatives Use for GW-4, GW-27, GW-32, GW-38 and GW-45 based polymer gels pH range 3-7, temperatures to 300°F (150°C) Varies with application Starch specific enzyme breaker Use for starch base polymers like FLC-42 and Adomite Regain pH range 3-11, temperatures to 250°F Varies with application Xanthan specific enzyme breaker Use for Xanthan base polymers pH range 3-4, temperatures to 275°F (135°C) Varies with application Enzyme breaker concentrate for Enzyme G, Enzyme G-LpH Use for guar specific polymer up to 300°F (149°C) high temperatures Effective in fluids that range in pH from 3 to 11 Diluted 33:1 for GBW-12 (Enzyme G) Enzyme breaker concentrate for Xantham Concentrated, dilute to use in Mudzyme X, EzClean X, Enzyme X Effective in fluids that range in pH from 3 to 4 100 gallons per 1000 Liquid enzyme breaker concentrate for high pH guar and celloluse based fluids Concentrated, dilute to use Dilute 9 parts water to 1 part GBW-15C (10:1)


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Breaker - Water GBW-15L

GBW-16C, Enzyme S

GBW-18

GBW-20C

GBW-23

GBW-23L

GBW-24

GBW-24L

GBW-26C

GBW-33D

GBW-5

GBW-7

High Perm CRB

High Perm CRB-LT


Enzyme breaker fluid system for high pH applications, and low temperatures Temperatures up to 140°F (60°C) Effective in fluids that range in pH from 7 to 11 0.1 to 2.5 gpt Starch specific enzyme breaker Use for starch base polymers like FLC-42 and Adomite Regain pH range 3-11, temperatures to 250°F Varies with application Solid oxidizing breaker for water based polymers Temperatures to 200°F (90°C) Requires catalyst below 120°F (50°C) 0.1 to 10 lb / 1000 gal Not compatible Reducing Agents Enzyme breaker concentrate for Northeast Region Use for guar specific polymer up to 300°F (149°C) high temperatures Effective in fluids that range in pH from 3 to 11 Usage should be 20:1 dilution to make Enzyme G-NE. High temperature delayed release breaker Temperatures from 225°F to 275°F (107-135°C) 0.5 to 2 ppt High temperature delayed release breaker slurry Temperatures from 225°F to 275°F (107-135°C) Mixed at 1 ppg 0.5 to 2 gpt Moderate temperature delayed release breaker Temperatures from 175°F to 275°F (79-135°C) 0.5 to 2 ppt Moderate temperature delayed release breaker slurry Temperatures from 175°F to 275°F (79-135°C) Mixed at 1 ppg 0.5 to 2 gpt Enzyme breaker concentrate for Enzyme C-HT Use for cellulose polymer below 250°F (121°C) high temperatures Typically 1 to 500 Solid enzyme breaker for high pH guar based fluids pH range 4-11.5 Effective at temperatures to 140°F (60°C) 0.1 to 10 lb / 1000 gal LT-22, KCL reduce activity (increase loading by 20% for 2% KCL) Solid oxidizing breaker for water based polymers Temperatures to 200°F (90°C) Requires catalyst below 120°F (50°C) 0.1 to 10 lb / 1000 gal Not compatible Reducing Agents Solid oxidizing breaker for remedial treatments Temperatures to 200°F (90°C), Requires catalyst below 140°F (60°C) May be utilized to remove Xanthan damage 0.1 to 10 lb / 1000 gal decomposes in warm moist air Encapsulated Oxidixing breaker for water base gels Provides delayed breaks for fracturing fluids Effective at temperatures from 175°F to 225°F (79-107°C) 0.25 to 10 lb / 1000 gal Encapsulated Oxidixing breaker low-moderate temperatures Provides delayed breaks for fracturing fluids Effective at temperatures from 70°F to 150°F (21-65°C) 0.25 to 10 lb / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Breaker - Water High Perm CRE

High Perm KP

High Perm KP-HT

Delayed release enzyme breaker slurry Provides controlled breaks for guar based fracturing fluids pH range 6-8, temperatures to 300°F (150°C) 0.5 to 10 lb / 1000 gal 2 lb = 1gal of Ultra Perm CRE Encapsulated Oxidixing breaker for water base gels Provides delayed breaks for fracturing fluids Effective at temperatures from 175°F to 225°F (79-107°C) 0.25 to 10 lb / 1000 gal Encapsulated Oxidixing breaker for water base gels Provides delayed breaks for fracturing fluids Effective at temperatures from 175°F to 225°F (79-107°C) 0.25 to 10 lb / 1000 gal

Breaker Catalyst BC-3

BC-31

BC-5

BC-6

Used to bring down pH of system. Can be used with all breakers. Used with enzyme breakers to lower pH of the system an allow the enzymes to work more effectively without Used to catalyst for oxidizers to spend their process in low to moderate temperatures. 1 gpt typical Dilution can be with US-40. Methanol may be an alternate to US-40 but not the preferred product. Low temperature liquid catalyst for oxidizing breakers Used with GBW-5 and GBW-7 at 80 to 140°F (27 to 49°C) May effect fluid pH and buffer loadings 1 to 2 gal / 1000 gal Used to bring down pH of system. Can be used with all breakers. Used with enzyme breakers to lower pH of the system an allow the enzymes to work more effectively without Used to catalyst for oxidizers to spend their process in low to moderate temperatures. 1 gpt typical Catalyst for oxidative breakers at temperatures below 120°F. Can be used as a buffer in fracturing systems.

Breaker System EzClean C-HT

EzClean G

EzClean S

EzClean S/X

EzClean X

Mudzyme C-HT


Enzyme breaker fluid system to remove cellulose polymer damage at high temperatures Contains metal complexers, buffers, and surfactants pH range 4-5, temperatures from 140°F to 250°F (60-121°C) Varies with application Enzyme breaker fluid system to remove guar polymer damage Contains metal complexers, buffers, and surfactants pH range 4-5, temperatures to 300°F (150°C) Varies with application Enzyme breaker fluid system to remove starch polymer damage Contains metal complexers, buffers, and surfactants pH range 6.5-8.5, temperatures to 230°F (110°C) Varies with application Enzyme breaker fluid system to remove Xanthan and starch polymer damage From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-7 pH Hole volume plus 20% Enzyme breaker fluid system to remove Xanthan polymer damage From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-8 pH Hole volume plus 20% Enzyme breaker fluid system to remove celloluse polymer damage From drilling applications at temperatures from 140°F to 250°F (60-121°C) Effective in fluids that range from 4-5 pH Hole volume plus 20%


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Breaker System Mudzyme S

Mudzyme S/X

Mudzyme X

Oxi Clean

Enzyme breaker fluid system to remove starch polymer damage From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-7 pH Hole volume plus 20% Enzyme breaker fluid system to remove starch and Xanthan polymer damage From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-8 pH Hole volume plus 20% Enzyme breaker fluid system to remove Xanthan polymer damage From drilling applications at temperatures up to 275°F (135°C) Effective in fluids that range from 4-8 pH Hole volume plus 20% Oxidizer based breaker flush system Chemically attacks and removes polymeric damage Effective at temperatures to 220°F (105°C) Varies with application

Crosslinker - Oil XLO-5

Crosslinker for Super Rheo Gel Use the exact same amount of XLO-5 as GO-64 component. May be added on-the-fly or batch mixed Normally used in 5-18 gals/1000 gals. of hydrocarbon fluid. Strong oxidizing agents

Crosslinker -Water Boric Acid

BXL-22WC

NPB-1 Sodium Borate

XLW-10 XLW-14

XLW-22C

XLW-24


Boric acid solid crosslinking agent for Viking gels Instant crosslink time, no delay Also used in acids and completion fluid systems 1 to 4 lb / 1000 gal Borate crosslinker with pH buffer-winterized version Instant crosslink time, no delay Replaced by XLW-10, being deleted 1-2 gpt Crosslinker for Viking frac fluid Borate based with some high ph control Solid crosslinking agent for Viking gels Also known as XLW-2, may be dissolved in water Used as cement retarder 1 to 4 lb / 1000 gal Borate crosslinker with pH buffer Rapid crosslink time, used for low temperature systems below 180°F (82°C) Zirconium crosslinker for Medallion HT gels Used in high pH formulations Crosslink time adjustable on-the-fly 0.25 to 1.5 gal / 1000 gal Can not be diluted. Zirconium crosslinker for Medallion gels Used in low pH CMHPG formulations, CO2 compatible Also used in guar systems at neutral pH 0.5 to 2 gal / 1000 gal 30-60% Borate crosslinker for Spectra Frac G gels Use for fluid temperatures less than 200°F (95°C) Crosslink time is variable 1 to 2.5 gal / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Crosslinker - Water XLW-30

XLW-30A

XLW-30B

XLW-32

XLW-4

XLW-40

XLW-40A

XLW-40B

XLW-41

XLW-41B

XLW-45

XLW-49

XLW-56

XLW-60

XLW-63

XLW-8


Borate crosslinker for Viking D gels Delayed high temperature, Crosslink time is adjustable on-the-fly 0.5 to 1.5 gal / 1000 gal Borate Crosslinker for Viking ID Delayed high temperature, Crosslink time is adjustable on-the-fly 0.5 to 1.5 gal / 1000 gal Borate Crosslinker for Viking ID Delayed high temperature, Crosslink time is adjustable on-the-fly Lower concentration of XLW-30A 0.5 to 3 gal / 1000 gal Liquid borate crosslinker for Viking gels For low temperature systems below 180°F (82°C) Instantly crosslinks gel 0.5 to 1.5 gal / 1000 gal Borate crosslinker for Viking gels Rapid crosslink time, used for low temperature systems below 180°F (82°C) Liquid additive for on-the-fly addition 1 to 2 gal / 1000 gal Crosslinker for 100% methanol system for West Texas Titanium based crosslinker Use in diluted form for 100% methanol system Diluted crosslinker for 100% methanol system for West Texas Titanium based crosslinker 4-6 gpt Diluted crosslinker for 100% methanol system for West Texas Titanium based crosslinker 4-6 gpt Titanium based crosslinker Metho Frac XL Crosslinker Surface crosslinker for delayed systems Blend of Titanium crosslinker and methanol Metho Frac XL Crosslinker 6 gpt recommended Titanium surface crosslinker for Medallion HT gels Used to accelerate crosslink time of XLW-60 systems Liquid additive for on-the-fly addition 0.1 to 0.75 gal / 1000 gal Zirconium crosslinker for Clean Plug Delayed crosslink for plug placement, crosslink time varies with pH Concentration must be doubled for heavy brines 1.5 to 3 gal / 1000 gal Borate crosslinker for Spectra Frac G gels Adjustable crosslink time delay Usable at all temperatures, but XLW-24 will be more economical below 150°F (65°C) 1.75 to 8 gal / 1000 gal Zirconium crosslinker for Medallion gel systems Primary crosslinker for both high and low pH fluids Crosslink time variable on-the-fly 0.75 to 2 gal / 1000 gal Crosslinker for Vistar system Zirconium based Crosslinker for low temperature system 0.25-1 gpt Borate crosslinker for Canada Lightning gels Rapid crosslink time, used for low temperature systems below 180°F (82°C) Liquid additive for on-the-fly addition 1 to 2 gal / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Crosslinker Delay XLD-1

XLD-30

Crosslink Delayer for High pH fluids Vistar and Medallion high pH Borate fluids of Spectra and Viking Vistar and Medallion 1/4 to 1/2 gpt is the recommended usage. Borates 1/4 to 1 gpt is recommended Care should be used as to much of the additive will cause the system not to crosslink at all Crosslink time delayer for XLW-30 Provides adjustable delay for Viking D systems using XLW-30 On-the-fly liquid additive 0.025 to 0.3 gal / 1000 gal

Fluid Loss - Stim Adomite Regain

FLC-17

FLC-42

FLC-42L

FLC-7

Degradable starch fluid loss additive--100% soluble Nalco's Adomite Regain For ungelled, gelled, or crosslinked fluids 10 to 50 lb / 1000 gal Liquid, solids free fluid loss agent for water-based fracturing fluids Non-ionic surfactant, effective to 350°F (175°C), for low to moderate permeabilities Controls fluid loss to formation face through the creation of microemulsions 5 to 15 gal / 1000 gal Degradable starch fluid loss additive--100% soluble, No internal breaker Use for gelled and crosslinked water base fracturing fluids Maintains damage free proppant pack and formation face 10 to 50 lb / 1000 gal Diesel slurry of FLC-42, degradable starch fluid loss additive--100% soluble Use for gelled and crosslinked water base fracturing fluids Each gallon of FLC-42L contains 4.5 lb FLC-42 2 to 10 gal / 1000 gal Non-damaging fluid loss additive, only use Northeast Region USA Limited usage Totally dissolves at 115°F in 30 minutes

Foam System Binary Foam

CO2 Foam

Metho Foam

N2 Foam

Exclusive CO2 / N2 foam blend for foam fracturing Works for water-sensitive zones, low pressured zones or tight gas formations. Variable gas content for specific conditions. Varies with application Carbon dioxide foam fracturing fluid for low permeability or low-pressure wells. Higher density allows lower surface treating pressures. Best results in reservoirs >90°F (32°C). Varies with application. Can precipitate asphaltenes and paraffins in certain crudes. Foamed methanol fracturing fluid for underpressured, water-sensitive formations. Reduces potential problems from load retention, clay swelling and clay migration. Can be used in either gas or oil formations. Varies with application. Foamed nitrogen fracturing fluid Works in low permeability, low bottomhole pressure and extremely sensitive formations. Can be used as diverting fluid, because of viscosity generated. Varies with application

Frac - Methanol Metho Frac XL


Methanol based fracturing system Use in very water-sensitive formations, low pressure reservoirs Good proppant transport, and viscosity Typically 50 pound system is used


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Frac - Oil Super Rheo Gel

Gelled oil system for hydraulic fracturing For use with diesel, kerosene, and a wide variety of crude oils and condensates Use for water sensitive formations, controlled break times using GBW-40 3-15 gpt of both components Best option to break fluid BF-9L, have to circulate into tank Could use caustic, acetic acid,

Frac - Water Aqua Frac

Medallion Frac

Medallion Frac HT

Spectra Frac G

Viking

Viking B

Viking C

Viking D

Vistar

Water based linear (non-crosslinked) gel system Formulated with any water based polymer or LFC slurry Included are guar, HPG, CMHPG, etc., not normally buffered 10 to 50 lb gel systems Low pH, CMHPG / Zirconium fracturing fluid system Temperatures to above 275 F (135°C), variable crosslink delay, CO2 compatible XLFC-3 or XLFC-3B polymer, XLW-60LPH or XLW-22C crosslinker, BF-10L buffer 25 to 50 lb systems High pH, CMHPG / Zirconium fracturing fluid system Temperatures to above 350°F (175°C), variable crosslink delay XLFC-3 or XLFC-3B polymer, XLW-60B or XLW-14 crosslinker, BF-7L or BF-9L buffers 25 to 70 lb systems Spectra Frac G Polyborate / guar fracturing fluid system Temperatures to above 350°F (175°C), variable crosslink delay XLFC-1 or XLFC-1B polymer, XLW-24 or XLW-56 Crosslinker, BF-7L buffer 25 to 50 lb systems Field results show compatibility w/ WSA-2 @ 5 gpt Low temperature borate / Guar fracturing fluid system Temperatures to 175 F (80°C), rapid crosslink XLFC-1 polymer, XLW-4 or XLW-32 crosslinker, BF-7L buffer 20 to 40 lb systems Low temperature borate / Guar fracturing fluid system (Canada) Temperatures to 175 F (80°C), rapid crosslink WG-15SLR polymer, XLW-4 or XLW-32 crosslinker, BF-7L buffer Low temperature borate / Guar fracturing fluid system (China) Temperatures to 175 F (80°C), rapid crosslink XLFC-1 polymer, CXB-6 crosslinker, BF-7L buffer High temperature delayed borate / guar fracturing fluid system Temperatures to above 300°F (150°C), adjustable crosslink delay XLFC-1 polymer, XLW-30 or XLW-30A crosslinker, BF-7L or BF-9L buffer 25 to 50 lb systems High pH, Low viscosity fracturing fluid system Temperatures to above 350°F (177°C), variable crosslink delay VSP-1 or VSP-2 polymer, XLW-63 or XLW-14 crosslinker, BF-7L or BF-9L buffers

Friction Reducer Steel FRS-12

Metal to metal friction reducer in sea-water, brines and muds typically 2% by volume

Gel Stabilizer GS-1A


Sodium thiosulfate gel stabilizer Used as a high temperature ( >200 °F) stabilizer for fracturing fluids and oxygen scavenger 1 lb GS-1A= 1.56 lb GS-1, 5.382 lb GS-1 = 1 gallon GS-1L Batch mix or "on-the-fly" 5-20 pptg Oxidizing breakers


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Gel Stabilizer GS-1L

Liquid thiosulfate gel stabilizer Used as a high temperature ( >200 °F) stabilizer for fracturing fluids and oxygen scavenger 3.45 lbs of GS-1A per gallon, 5.382 lb GS-1 = 1 gallon GS-1L Batch mix or "on-the-fly" 1-5 gpt Oxidizing breakers

Gellant - Methanol GM-55

XLFCM-1

HPG Gelling Agent for 100% Methanol Used in Metho Frac XL system and XLFCM-1 slurry 50 lbs per 1000 gallons of methanol HPG liquid fracturing concentrate polymer slurry Utilizes GM-55 polymer for Metho Frac XL fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal

Gellant - Oil GO-64

Oil gelling agent for Super Rheo Gel Used with XLO-5/GBO-5L or GBO-6 May be added on-the-fly or batch mixed Normally used in 3-18 gals/1000 gals. of hydrocarbon fluid. Avoid contact with strong oxidizing agents.

Gellant -Surfactant MA-1

Surfactant gel for international use only Biodegradable anionic surfactant

Gellant - Water GLFC-1

GLFC-1B

GLFC-1C

GLFC-1D

GLFC-5

GLFC-5B

GLFC-5C


Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Lower bicarbonate level than LFC-1B 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-3 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-3 polymer for Spectra Frac and Viking fluid systems Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal High Yield Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-3 polymer for Viking fluid systems Lower bicarbonate level than XLFC-1B 5 to 15 gal / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Gellant - Water GLFC-5D

GW-21

GW-22

GW-22L

GW-24LE

GW-27

GW-27LE GW-28

GW-28KF

GW-28LC

GW-28LE

GW-3

GW-32

GW-38


Guar gum liquid fracturing concentrate polymer slurry with environmental base fluid Utilizes GW-3 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal HEC (Hydroxyethyl Cellulose) gelling agent, HEC-25 Used primarily in gravel packing fluids, and as an acid gellant Easier to hydrate than AG-21R 20 to 150 lb / 1000 gal Clarified, purified Xanthan gum gelling agent Used primarily in gravel packing fluids, and in some drilling muds to improve displacement efficiency Primary function to provide solids transport, solids suspension, friction reduction 10 to 50 lb / 1000 gal Tri-valent ions such as chromium Clarified, purified Xanthan gum gelling agent slurry Used primarily in gravel packing fluids, and in some drilling muds to improve displacement efficiency Primary function to provide solids transport, solids suspension, friction reduction 1 quart is equal to 1 pound dry, Hole cleaning 1-2 qt/bbl Friction reduction 1 qt/bbl, Tri-valent ions such as chromium Slurried HEC (Hydroxyethyl Cellulose) gelling agent, slurried in an environmentally friendly carrier Same polymer as GW-21 (HEC-25) 3.45 lb GW-21 per gallon of slurry 10 to 50 gal / 1000 gal Contact with Alkali materials Refined guar gum gelling agent Contains buffer to aid in hydration Sacked material for batch mixed treatments, and Polyemulsion systems 10 to 50 lb / 1000 gal Guar gum slurry gelling agent, slurried in an environmentally friendly carrier 3.22 lbs active guar per gallon CMHEC (Carboxymethyl Hydroxyethyl Cellulose) gelling agent Low residue cellulose derived polymer Used for Clean Plug and some fracturing fluids 20 to 80 lb / 1000 gal Highly concentrated liquid dispersion of a high quality, anionic, water soluble polymer (CMHEC) Carrier solution organic potassium salt solution Used for Clean Plug and some fracturing fluids typically requires between 2.1 and 2.5 gallon per barrel of completion fluid CMHEC slurry Low residue cellulose derived polymer Used for Clean Plug and some fracturing fluids CMHEC slurried in an environmentally friendly carrier Low residue cellulose derived polymer Used for Clean Plug and some fracturing fluids Guar gum gelling agent High yield, refined guar for fresh water, seawater, and brines Gellant in XLFC-5 systems HPG (Hydroxyproply Guar) gelling agent High yield, low residue guar derivative Used with water, brines, and weak acids 20 to 50 lb / 1000 gal CMHPG (Carboxymethyl Hydroxyproply Guar) gelling agent High yield, low residue guar derivative for fresh water, seawater, and brines Gellant in XLFC-3 and XLFC-3B for Medallion fluid systems 20 to 50 lb / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Gellant - Water GW-3LD Green

GW-3LE

GW-4

GW-4 AFG

GW-45

VSP-1

VSP-2

XLFC-1

XLFC-1B

XLFC-1C

XLFC-1D

XLFC-2B

XLFC-3

XLFC-3B

XLFC-3C


Guar gum slurry gelling agent, slurried in an environmentally friendly carrier 4 pounds active per gallon of slurry. No buffer Use the same as XLFC-5D Guar gum slurry gelling agent, slurried in an environmentally friendly carrier 3.22 lbs active guar per gallon Usage Gulf of Mexico Guar gum gelling agent Refined guar for fresh water, seawater, and brines Gellant in XLFC-1 and XLFC-1B for Spectra Frac and Viking fluid systems 20 to 50 lb / 1000 gal Guar gum gelling agent, for North Sea, Fine ground High yield, refined guar for fresh water, seawater, and brines Gellant in XLFC-1 and XLFC-1B for Spectra Frac and Viking fluid systems 20 to 50 lb / 1000 gal CMG (CarboxyMethyl Guar) gelling agent High yield, low residue guar derivative Gellant for Vistar and other systems Used only in VSP slurries. Vistar polymer slurry Utilizes GW-45 polymer Stable low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 3 to 15 gal/1000 gal Vistar polymer slurry with buffer Utilizes GW-45 polymer Contains bicarbonates for improved fluid stability at high temperatures 3 to 15 gal/1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Lower bicarbonate level than LFC-1B 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-4 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal HPG liquid fracturing concentrate polymer slurry Utilizes GW-32 polymer Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal CMHPG liquid fracturing concentrate polymer slurry Utilizes GW-38 polymer for Medallion fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal CMHPG liquid fracturing concentrate polymer slurry Utilizes GW-38 polymer for Medallion fluid systems Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal CMHPG liquid fracturing concentrate polymer slurry Utilizes GW-38 polymer for Medallion fluid systems Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Gellant - Water XLFC-4

XLFC-5

XLFC-5B

XLFC-5C

XLFC-5D

CMHEC liquid fracturing concentrate polymer slurry used for water based fracturing operations Utilizes GW-28 polymer 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-3 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-3 polymer for Spectra Frac and Viking fluid systems Contains bicarbonates for improved fluid stability at high temperatures 5 to 15 gal / 1000 gal High Yield Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-3 polymer for Viking fluid systems Lower bicarbonate level than XLFC-1B 5 to 15 gal / 1000 gal Guar gum liquid fracturing concentrate polymer slurry Utilizes GW-3 polymer for Spectra Frac and Viking fluid systems Stable, low viscosity slurry, hydrates rapidly and is easily metered on-the-fly 5 to 15 gal / 1000 gal

Miscellaneous CA-1

Stabilizing agent for slurries Used in GBW-23L and GBW-24L

Oil Emulsion Polyemulsion

Emulsified fracturing fluid system, oil in gelled water, one part water to two parts oil Emulsion will break in the reservoir, use with diesel, kerosene, or lease crudes High viscosity, economical fluid system for water sensitive formations Varies with application

pH Control Additive Ammonium

BF-10L

BF-12L BF-15L

BF-16L

BF-7L

BF-8L


30%, Ammonium hydroxide solution (26 Be) Hydroxide,30% Strong base, also available as a 15% solution pH = 9-11 in water Varies with application Low pH liquid buffer, Weak acid, pH = 3-6 in water Used for Medallion or Quadtra Frac 0.5 to 2 gal / 1000 gal Vistar low pH buffer or Medallion LpH Hydrocarbon solution used to slow release of the buffer, allowing slower crosslink of the fluid. High pH Buffer, adjust fracturing gels into the range of 10.5 to 12.5 Primarily used for high temperatures Used in Russia, High pH Buffer, adjust fracturing gels into the range of 10.5 to 12.5 Primarily used for high temperatures in Vistar II HT Used in Russia, China 1-3 gpt Above 4 gpt can affect break times Liquid high pH buffer Used for Medallion Frac HT, Spectra Frac G, and Viking systems pH = 9-11 in water 0.5 to 5 gal / 1000 gal High pH buffer for use in sea-water systems Helps prevent hydroxide precipitation pH 8-10 in water Varies with application Corrosive in nature


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS pH Control Additive BF-9L

Caustic Soda, Dry

Caustic Soda, Liquid

Fumaric Acid

Sodium Acetate

Sodium Bicarbonate

Sodium Bicarbonate Liquid

Sodium Carbonate

Sodium Diacetate Sulfamic Acid

High pH buffer Used for Viking D and Spectra Frac at high temperatures pH 9.5 to 11.5 in water 0.5 to 4 gal / 1000 gal Solid Sodium Hydroxide Available in pellets or flakes or beads Strong base, pH 10-12 in water Varies with application Sodium Hydroxide solution Available in various strengths to 50% Strong base, pH = 10-12 in water Varies with application Weak acidic buffer for fracturing systems Sequesters iron in acid systems. pH = 4-7 in water Varies with application low pH buffer Weak base, used to buffer XLFC slurries Also performs as an oil gel breaker Varies with application Solid, high pH buffer Sodium bicarbonate buffer Weak base, pH 7-8 in water Varies with application Liquid, high pH buffer Sodium bicarbonate slurry Weak base, pH 7-8 in water Varies with application 0.1 to 2 gal / 1000 gal is approx 50 - 1000 ppm Bicarbonate Solid high pH buffer Soda ash, sodium carbonate pH = 9-11 in water Varies with application Solid low pH buffer, readily disolvable in water. Stronger buffering ability than sodium acetate to lower pH. Low pH buffer, weak acid Sulfamic acid pH = 2-4 in water Varies with application

Proppant Flowback FlexSand™ HS

FlexSand™ LS

FlexSand™ MSE


For high closure stress and temperatures While at the same time maintaining fracture conductivity can be applied in oil and gas wells. For high closure stress (above 6000 psi) and temperatures up to 400°F (204°C). 10-15% of the total amount of proppant. Controls proppant flowback and reduces the effect of stress on the proppant grains. While at the same time maintaining fracture conductivity can be applied in oil and gas wells. For low closure stress below 1500 psi and moderate temperatures up to 150°F (66°C). 10-15% of the total amount of proppant. Controls proppant flowback and reduces the effect of stress on the proppant grains. While at the same time maintaining fracture conductivity can be applied in oil and gas wells. For closure stress between 1500-7000 psi and moderate temperatures up to 275°F (135°C). 10-15% of proppant volume


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Resin Activator Activator Borden

Activator Oil, Borden

Activator Superset-O

Activator Superset-P

Activator Superset-W

Curable resin activator for resin coated proppants at low BHST in water base fluids Surfactant in IPA 5 gallon container, use for Borden curable resin coated proppants 5-15% by vol of Frac Fluid Oil gels Oxidizers Curable resin activator for resin coated proppants at low BHST in oil base fluids Surfactant in diesel Use at low BHST, use for Borden curable resin coated proppants 5-15% by vol of Frac Fluid Curable resin activator for resin coated proppants at low BHST in oil base fluids Surfactant in diesel Use at low BHST, use for Santrol curable resin coated proppants 5-15% by vol of Frac Fluid Curable resin activator for resin coated proppants at below 100°Fin water base fluids Surfactant in Alcohol Use with Santrol PolarProp curable resin coated proppants 5-15% by vol of Frac Fluid Curable resin activator for resin coated proppants at low BHST in water base fluids Surfactant in Alcohol Use at low BHST, use for Santrol curable resin coated proppants 5-15% by vol of Frac Fluid

Salt Ammonium Chloride

Potassium Chloride

Ammonium Chloride Salt Used to inhibit clay swelling. Recommended usage varies from 1-5% Ammonium chloride by weight in water. Incompatible with metals, metal oxides, amines, carbonates, alkalies. Incompatible with lead and silver salts, potassium chlorate. Potassium Chloride Salt (KCL) Used to prevent formation clays from swelling in cementing and fracturing. 2-5% typically for fracturing 1-10% for cementing Concentrations above 10% cause cement to develop high viscosities.

Sand Control Clean Plug

Curing Agent-1A Epoxy-1A Furfuryl Alcohol S-2

San-Stop Aqua Pad

SC Resin Base 1330


Temporary crosslinked blocking gel Protect permeable zones from invasion by potentially damaging workover fluids. Can be mixed with heavy weight fluids. Calculate a 5 feet radial pore volume. Curing agent for San-Stop Aqua sand control system Component of San-Stop Aqua sand control system Epoxy resin Furfuryl alcohol for SC Resin II Component of San-Stop Aqua sand control system San-Stop Aqua Sand consolidation system with proppant Water-based, in-situ functional from 100° to 200°F (38° to 93°C). Sets-up downhole as a permeable, consolidated sandstone. 2-3 cubic ft (0.06-0.09 cubic meter) sand /ft of perfs Sand consolidation system (pad) Water-based, in-situ functional from 100° to 200°F (38° to 93°C). Sets-up downhole as a permeable, consolidated sandstone. 15-35 gal/ft (186-435 l/m of perforations Used in SC Resin II Combines the alcohol and the resin in one drum. SC Resin Fixer Activator for SC Resin sand control system 0.5 gallon per batch of SC Resin


BJ SERVICES PRODUCT LINE DETAILED DESCRIPTIONS AND APPLICATIONS Sand Control SC Resin II

Terra Pack II

Terra Pack III

Thermo Plug I

Thermo Plug II


Insitu sand consolidation system Lower toxicity than comparable epoxy resin No less than 90 gallons of SC Resin II per foot of perforated interval HEC gravel pack fluid High viscosity, non-crosslinked carrier fluid for gravel packing operations. Salt compatible, normally 3% Ammonium Chloride 10-100 lbs/1000 gallons of water Xanthan gravel pack fluid Moderate viscosity, non-crosslinked carrier fluid for gravel packing operations. Salt compatible, normally 3% Ammonium Chloride 36-48 lbs/1000 gallons of water High temperature 200-350°F (93-177°C), temporary blocking gel Protect permeable zones from invasion by potentially damaging workover fluids. Hydrates in the wellbore during pumping. Old name High Temperature Blocking gel Varies with application High temperature 200-350°F (93-177°C), temporary blocking gel Protect permeable zones from invasion by potentially damaging workover fluids. Varies with application


Cement Laboratory Testing Section 9

Printed: 6/12/2006

EDC, Tomball, TX

API Testing O O O O

API Specifications and Recommendations Definitions Temperatures Laboratory Testing

Slide 2

EDC, Tomball, TX

1

API Specifications for Cements and Materials for Well Cementing O

API Spec 10A (October 2002) ³ ISO 10426-1:2000 ³ Specifies Chemical, Physical and Performance requirements for API cements and neat slurries. Ë MgO, SO3, C3A, C3S, C4AF Ë Loss on ignition, Insoluble residue, Fineness Ë Compressive Strength, Free Water, Thickening Time

³ Specifies required equipment Ë Calibration procedures Ë Testing procedures Slide 3

EDC, Tomball, TX

API Recommended Practice for Testing Well Cements O

API RP 10B-2 (July 2005) ³ Specifies procedures for testing and determining properties of cement slurries and set cement. Ë Sampling, Preparation, Density Ë Compressive Strength, Thickening Time, Fluid Loss Ë Permeability, Rheology, Stability, Compatibility

³ Specifies required equipment Ë Calibration procedures Ë Testing procedures

Slide 4

EDC, Tomball, TX

2

Definitions O

BHST ³ Bottomhole Static Temperature, °F & °C

O

BHCT ³ Bottomhole Circulating Temperature, °F & °C

O

BHSqT ³ Bottomhole Squeeze Temperature, °F & °C

O

BHLT ³ Bottomhole Logging Temperature, °F & °C

Slide 5

EDC, Tomball, TX

Definitions O

PsTG ³ Pseudo Temperature Gradient, °F/100 ft & °C/100 m ³ Similar to geothermal gradient

O

MD ³ Measured Depth, ft

O

TVD ³ True Vertical Depth, ft

Slide 6

EDC, Tomball, TX

3

Temperature O O

Most Important factor in slurry design Higher temperature ³ Escalates Hydration ³ Decreases thickening time ³ Generally decreases slurry viscosity ³ Generally increases fluid loss, compressive strength, free fluid and segregation/settling

Slide 7

EDC, Tomball, TX

PsTG O

Pseudo Temperature Gradient, °F/100 ft & °C/100 m ³ Similar to geothermal gradient Ë BHST = 80 + PsTG x TVD / 100 ¸ PsTG = Pseudo Temperature Gradient, °F/100 ft ¸ TVD = True Vertical Depth, ft

³ Assumes linear geothermal gradient ³ Assumes surface temperature of 80 °F ³ Maps exist for geothermal gradients in US

Slide 8

EDC, Tomball, TX

4

BHST O

Bottomhole Static Temperature ³ Can be estimated Ë BHST = 80 + PsTG x TVD / 100 ¸ PsTG = Pseudo Temperature Gradient, °F/100 ft ¸ TVD = True Vertical Depth, ft

³ Measurements are preferred

Slide 9

EDC, Tomball, TX

BHST Calculation for Canada O O

Thermal Gradient Calculation Deviates from API due to cooler ambient surface conditions ³ BHST (°C) = depth (m) x T.G. (°C/100 m) + 4.4 °C ³ BHST (°F) = depth (ft.) x T.G. (°F/100 ft.) + 40 °F

O

O

Very little current data available on thermal gradients in Canada Best method is EUB and other published temperature data Slide 10

EDC, Tomball, TX

5

BHST from Temperature Logs O

Logging Temperature (BHLT) ³ BHST = BHLT, if the well has been static 36 hours or more ³ If static time is < 36 hrs, use one of two methods to estimate BHST

Slide 11

EDC, Tomball, TX

Method 1 (Multiplication Factor) Time Since Last Circulation

Multiplication Factor (BHST/BHLT)

0 – 6 hours

1.20

6 – 12 hours

1.18

12 – 18 hours

1.15

18 – 24 hours

1.12

> 36 hours

1.00 Slide 12

EDC, Tomball, TX

6

Method 2 (Extrapolation) O

Need temperature from three log runs ³t ³ ∆t ³ tp

O O

= circulation time, hrs = time after circulation (static), hrs = dimensionless time = ∆t/(t + ∆t)

Plot BHLT vs tp on semi-log scale Extrapolate BHST @ tp = 1

Slide 13

EDC, Tomball, TX

Method 2 (Extrapolation)

Slide 14

EDC, Tomball, TX

7

BHCT O

Bottomhole Circulating Temperature ³ Definition Ë BHCT is the temperature the slurry will obtain while being pumped into place

³ Function of: Ë Ë Ë Ë Ë Ë Ë Ë

BHST Circulating rate Circulating time Surface temperature Depth Mud type (oil or water) Hole geometry Rock type Slide 15

EDC, Tomball, TX

BHCT O

Notes on BHCT ³ BHCT is much lower than BHST ³ Maximum temperature occurs 1/3 to ¼ of the way up the annulus ³ Time-dependent (true steady state is never attained) Ë After 1 or 2 complete circulations, the temperature change is negligible

³ While tripping, wellbore fluid heats up to within 10% of geothermal gradient after 15 hours of trip time ³ API data for casing BHCT was collected from 66 wells Ë API data standard deviation is 16.6 °F

Slide 16

EDC, Tomball, TX

8

Determining BHCT O

Casing or Liner Jobs ³ Depths < 10,000 ft Ë BHCT is estimated from API Spec 10, Table 4, Schedules 9.2 – 9.7 and Table 5, Schedules 9.14 – 9.19

³ Depths > 10,000 ft BHCT = 80 +

( 0.006061 x TVD x PsTG ) − 10.0915

(

1.0 − 0.1505 x 10 − 4 x TVD

)

Standard Deviation = 16.6 °F

³ Or use BJ WellTemp™ Software Slide 17

EDC, Tomball, TX

Determining BHCT SI Units O O O

O

From API RP 10B-2 / ISO 10426-2 See page 33 for SI unit equation Problem with method is there is limited new data on TG thermal gradients in Canada which limits use of equation Revised terms for BHCT, TVD, etc. used in new edition

Slide 18

EDC, Tomball, TX

9

Determining BHCT By Calculation in Canada O O

Calculations relating depth and BHST Two calculations: ³ Casing and liner ³ Squeeze and plug

Slide 19

EDC, Tomball, TX

BHCT Calculation Method Canada Depth (m) Casing, Liner Squeeze, Plugs ------------------------------------------------------------------------------------------------------305 .198(BHST)+21 .533(BHST)+12 610 .367(BHST)+17 .600(BHST)+11 914 .378(BHST)+17 .600(BHST)+11 1219 .383(BHST)+16 .600(BHST)+11 1524 .373(BHST)+17 .600(BHST)+10 1829 .366(BHST)+17 .622(BHST)+10 2134 .371(BHST)+17 .648(BHST)+8 2438 .375(BHST)+17 .658(BHST)+9 2743 .400(BHST)+16 .681(BHST)+9 3048 .427(BHST)+15 .707(BHST)+8 3353 .473(BHST)+14 .721(BHST)+7 3658 .511(BHST)+13 .739(BHST)+7 3962 .559(BHST)+12 .759(BHST)+6 4267 .600(BHST)+11 .771(BHST)+6 4572 .653(BHST)+9 .787(BHST)+6 4877 .700(BHST)+8 .796(BHST)+5 5182 .761(BHST)+6 .809(BHST)+5 5486 .850(BHST)+6 .819(BHST)+5

Slide 20

EDC, Tomball, TX

10

Determining BHCT O

Temperature tables from the Cement Engineering Support Manual ³ See end of section

Slide 21

EDC, Tomball, TX

Example Calculation BHST/BHCT O

Vertical Well ³ Geothermal Gradient 1.5 °F/100ft ³ Depth 8,000 ft (2438 meters) ³ BHST = 80 + (1.5 x 8,000/100) = 200 °F ³ BHCT = 140 °F Ë Cement Engineering Support Manual Section 6.3 Temperature Information, Table 2

Slide 22

EDC, Tomball, TX

11

Example Calculation Canada O O

BHST( °F)= 40 + (1.5x8000/100) = 160 °F BHST ( °C) = 5/9 (160 – 32) = 71 °C ³ °C = 5/9(°F-32)

O

BHCT (°C) = 0.375 (71) + 17 = 44 °C ³ Calculation for 2438 m = 0.375 (BHST °C) + 17

Slide 23

EDC, Tomball, TX

BHCT in Horizontal Wells O

API correlations were developed for vertical wells ³ For Wells with < 30° inclination Ë Estimate BHST normally

O

In horizontal wells, slurry is circulated at maximum TVD for a much longer time ³ Use BJ WellTemp™ Software or ³ Estimate with Alternative Calculation method

Slide 24

EDC, Tomball, TX

12

BHCT in Horizontal Wells (cont.) O

Alternate Calculation Method ³ For Wells with > 30° inclination Ë Calculate PsTG from measured depth (MD) instead of TVD

PsTG =

( BHST − 80 ) x 100 MD

Ë Look up or calculate BHCT using PsTG and MD

Slide 25

EDC, Tomball, TX

Slide 26

EDC, Tomball, TX

13

BHSqT O

Bottomhole Squeeze Temperature ³ Squeeze temperatures are generally higher than circulating temperatures ³ BHSqT may be estimated from API Spec 10 Ë Table 6, Schedules 9.26 – 9.37 (Continuous Pumping Squeeze) Ë Table 7, Schedules 9.38 – 9.49 (Hesitation Squeeze)

Slide 27

EDC, Tomball, TX

BHSqT (cont.) ³ BHSqT may also be predicted with this formula:

BHSqT = 80 +

( 0.0076495 x TVD x PsTG ) − 8.2021 1.0 − ( 0.807 x 10 −5 x TVD )

Standard Deviation = 13.0 °F

Slide 28

EDC, Tomball, TX

14

BHSqT SI Units O O O

O

API RP 10B-2 / ISO 10426-2 SI unit equation on page 37 Revised terms for BHCT, TVD, etc. used in new edition Same problem little new thermal gradient available in Canada limits its use

Slide 29

EDC, Tomball, TX

Laboratory Testing O

O O O O O O O

Slurry Preparation & Conditioning Thickening Time Fluid Loss Rheology Gel Strength Thixotropy Compatibility Compressive Strength

O

O O

O

Flexural & Tensile Strength Free Fluid Slurry Segregation/Settling Gas Flow Model

Slide 30

EDC, Tomball, TX

15

Slurry Preparation and Conditioning O

Mixing ³ Simulates field mixing conditions ³ Mix the water, cement and additives in API mixer (Waring blender) at low speed Ë 4,000 rpm during 15 seconds

³ Shear at high rate Ë 12,000 rpm for 35 seconds

Slide 31

EDC, Tomball, TX

Slurry Preparation and Conditioning (cont.) O

Conditioning ³ Simulates slurry agitation while traveling through the pipe ³ Place slurry in consistometer and continue stirring while heating up to BHCT and pressuring up to BHP

Slide 32

EDC, Tomball, TX

16

API Mixer

Slide 33

EDC, Tomball, TX

Consistometers

Atmospheric Consistometers Pressurized Consistometers

Fann 35 Rotational Viscometer Slide 34

EDC, Tomball, TX

17

PC-10 Consistometer

Slide 35

EDC, Tomball, TX

Consistometer Parts

Slide 36

EDC, Tomball, TX

18

Thickening Time O

Pumpability time ³ Measured by Consistometer Ë Atmospheric (BHCT < 194 °F or < 90 °C) Ë Pressurized

³ Bearden units of consistency, Bc Ë Related to torque imparted on the paddle shaft Ë Measured with a voltage potentiometer Ë Slurry is usually considered unpumpable at 70 – 100 Bc

³ Test is performed at BHCT Ë Conditioning time, heat-up rate and pressure are determined by API Spec 10 tables Ë Once BHCT is reached, it is maintained constant Slide 37

EDC, Tomball, TX

Thickening Time (cont.) O

Types of slurry: ³ Gel Set Ë Drag Set

³ Right Angle Set

Slide 38

EDC, Tomball, TX

19

Thickening Time (cont.) O

Batch Mixing ³ Slurry is conditioned (stirred) at atmospheric conditions to simulation batch mixing time Ë Typically one hour

³ Reported thickening time does not include batch mix time O

Hesitation Squeeze ³ Second temperature heat-up (ramp) from BHSqT to BHST ³ Slurry stirring is cycled on/off during second temperature ramp to simulate hesitation method ³ Generally gives shorter thickening time than Continuous Pumping Squeeze Slide 39

EDC, Tomball, TX

Fluid Loss O

O

Fluid loss is the rate at which water will be forced out of the cement slurry into permeable formations, expressed in mL/30 min Measured with a Fluid Loss Cell ³ Slurry is mixed and conditioned to BHCT before doing leak-off ³ Cell consists of a pressurized cylinder with a 325 mesh screen insert to simulate permeable formations ³ 1,000 psi pressure differential is applied ³ Filtrate is collected during a 30 minute interval and measured ³ Standard Cell or Stirred Fluid Loss Cell Slide 40

EDC, Tomball, TX

20

Fluid Loss Test at High Temperature O O

BHCT > 194 °F or > 90 °C Method 1 (Standard Fluid Loss Cell) ³ Condition slurry to BHCT in pressurized consistometer ³ Cool slurry to 194 °F or 90 °C ³ Transfer slurry to pre-heated fluid loss cell ³ Increase temperature to BHCT ³ Perform fluid loss test

Slide 41

EDC, Tomball, TX

Fluid Loss Test at High Temperature O O

BHCT > 194 °F or > 90 °C Method 2 (Stirred Fluid Loss Cell) ³ Condition slurry to BHCT in stirred fluid loss cell ³ Invert cell ³ Apply differential pressure ³ Perform fluid loss test

O

Safer, Easier & More Representative Slide 42

EDC, Tomball, TX

21

Standard Fluid Loss Cells & Parts

Slide 43

EDC, Tomball, TX

Stirred Fluid Loss Cell

Slide 44

EDC, Tomball, TX

22

Rheology O

O

O

Rheology is the study of flow and deformation of fluids Needed to calculate friction pressures and to predict flow regimes Rheology is the relationship between flow rate (shear rate) and the pressure (shear stress) needed to move a given fluid ³ Shear Rate (SR) = difference in velocity of two fluid particles divided by the distance between them ³ Shear Stress (SS) = frictional force created by the two fluid particles rubbing against each other Slide 45

EDC, Tomball, TX

Fann-35 Rotational Viscometer O

O O

Stationary cup and rotating sleeve Internal shaft & bob Shear Rate ³ Proportional to rotational speed ³ Shear Rate = 1.7023 X RPM

O

Shear Stress ³ Proportional to torque imparted on shaft ³ Shear Stress = 1.065 x Dial Reading

Slide 46

EDC, Tomball, TX

23

Fann-35 Rotational Viscometer (cont.) O

O

Measurements are generally taken at ambient temperature (to simulate mixing conditions) and BHCT (to simulate pumping conditions) General Rules of Thumb ³ Low end readings (3 & 6 rpm) of less than 5 indicate the possibility of solids settling ³ A low end reading of greater than 20 indicates a strong possibility of gelation ³ High end readings (300 & 600 rpm) of greater than 200 could indicate difficulty in field mixing and pumping Slide 47

EDC, Tomball, TX

Rheological Models O

Newtonian Model ³ SS is directly proportional to SR ³ Viscosity = slope of SS vs SR x 478.8, cp ³ Water, gasoline, diesel, light oils

O

Bingham Plastic Model ³ Fluid will remain static until a certain minimum SS is applied, then SS is proportional to SR ³ Yield Point (YP) = minimum SS to move fluid, lbf/100 ft2 ³ Plastic Viscosity (PV) = slope of SS vs SR x 478.8, cp ³ Cement slurries, drilling muds, cementing spacers and preflushes

Slide 48

EDC, Tomball, TX

24

Shear Stress (lbf/100ft^2)

Newtonian vs Bingham Plastic 100 90 80 70 60 50 40 30 20 10 0

YP = 32 lbf/100ft2 PV = slope x 478.8 = 57 cp

Viscosity = slope x 478.8 = 51 cp 0

100

200

300

400

500

600

Shear Rate (1/s) Slide 49

EDC, Tomball, TX

Rheological Models (cont.) O

Power Law Model ³ SS is proportional to SR to the power of n’ Ë Log(SS) is proportional to log(SR)

³ Flow Behavior Index (n’) Ë Slope of log(SS) vs log(SR) Ë Normally, n’ is less than one

³ Consistency Index (K’) Ë Intercept of log(SS) vs log(SR) / 100 * ((3n’ + 1)/4n’)^n’ Ë Units in lbf•sn’/ft2

³ Cement slurries, drilling muds, cement spacers and preflushes Slide 50

EDC, Tomball, TX

25

Power Law Model K’ = 0.0722 lbf•sn’/ft2

Shear Stress (lbf/100ft^2)

100

N’ = slope = 0.4211 10

1 1

10

100

1000

Shear Rate (1/s) Slide 51

EDC, Tomball, TX

Choosing Rheological Model O O

Plot Shear Stress vs Shear Rate on linear and log-log coordinates Determine which coordinates give the best straight line: ³ If linear: Use Bingham Plastic ³ If log-log: Use Power Law

O

Alternatively, use linear regression technique to determine coefficient of regression ³ Choose model with coefficient of regression closest to 1.000 Slide 52

EDC, Tomball, TX

26

Gel Strength O O

Force required to initiate fluid movement Measure on Fann-35 ³ ³ ³ ³ ³

Mix and condition slurry to BHCT Take rheology readings Stir for 60 seconds at 600 rpm Stop for 10 seconds Turn on 3 rpm, observe maximum dial reading (will break back),multiply by 1.065 Ë 10 second gel strength

³ Stop for 10 minutes ³ Repeat 3 rpm reading, multiply by 1.065 Ë 10 minute gel strength Slide 53

EDC, Tomball, TX

Gel Strength (cont.) O

Pressure required to start movement of a column of fluid is a function of the gel strength, column height, and crosssectional area P = Sg x L / (300 x D) P = Pressure, psi Sg= Gel Strength, lbs/100 ft2 L = Length, ft D = Casing Diameter, inches Slide 54

EDC, Tomball, TX

27

Thixotropy O O

Thixotropic slurries become semi-solid at rest and liquid when agitated Test with Fann-35 ³ After standard gel test, agitate at 600 rpm for 60 seconds, stop 10 seconds, measure initial gel strength, G(i) ³ Leave slurry static for 10 minutes ³ Agitate at 600 rpm for 60 seconds, stop 10 seconds, and measure gel strength again, G(f) ³ To be considered thixotropic, G(f) should be at least 20% greater than G(i) Slide 55

EDC, Tomball, TX

Thixotropy (cont.) O

Alternate Test Method (Cup) ³ Pour slurry in paper or styrofoam cup ³ Leave static 2 minutes ³ Invert cup to test for pourability ³ Repeat every minute until slurry is unpourable ³ Stir with glass rod 15 seconds ³ Check if slurry is pourable, if yes, then record time as initial gel set time ³ Repeat procedure ³ A good slurry should be able to be sheared 3 times before becoming too viscous to pour Slide 56

EDC, Tomball, TX

28

Compatibility Testing O

Spacer / Mud ³ Viscous mixtures ³ Precipitation

O

Spacer / Cement ³ Viscous mixtures ³ Premature cement setting

O

Mud or Displacement Fluid / Cement ³ Viscous mixtures ³ Premature cement setting Slide 57

EDC, Tomball, TX

Compatibility Testing (cont.) O

Take rheology readings of mixtures ³ 100% spacer ³ 75% spacer ³ 50% spacer ³ 25% spacer ³ 0% spacer

0% mud 25% mud 50% mud 75% mud 100% mud

Slide 58

EDC, Tomball, TX

29

Example Test Results Fann-35 Dial Reading

Mud/Spacer Mixture % by volume

600

300

200

100

6

3

100% Mud

42

28

22

15

4

3

95% Mud / 5% Spacer

40

27

21

14

4

3

75% Mud / 25% Spacer

35

23

19

13

3.5

3


25

17

13

9

3

2.5


20

13

11

7

2.5

2

5% Mud / 95% Spacer

16

11

9

6

2

1.5

100% Spacer

12

9

7

5

1.5

1 Slide 59

EDC, Tomball, TX

Example Test Results (cont.) PV 3

n’ 0.4150

Spacer Rheology

300 rpm Dial Reading

YP 6 lbs/100ft2 K’ 0.0145 lb•secn’/ft2 50 40 30 20 10 0 0

5

25

50

75

95

100

% Spacer Slide 60

EDC, Tomball, TX

30

Wettability Tester

Slide 61

EDC, Tomball, TX

Compressive Strength O

O

Measured in psi, and is a function of Time and Temperature How much do we need? ³ Traditional rules of thumb Ë Ë Ë Ë Ë

5 to 200 psi to support casing 500 psi to continue drilling 1,000 psi to perforate At least 2,000 psi to stimulate & isolate zones Enough strength to side track (more than adjacent formation)

³ Mechanical integrity calculations and experience show we may not need as much as we traditionally thought Ë LOTIS Technology and IsoVision software Slide 62

EDC, Tomball, TX

31

Compressive Strength Effect of Confining Stress Unconfined Measurements Confined Measurements Confining Stress UCS psi C.S. psi psi

Class G

7160

11,720

3,000

6,040

15,130

5,000

3,520

11,800

5,000

4,700

12,150

5,000

3,540

9,200

1,000

12,500

2,000

Neat

Class H

14,500

4,000

1,780

13,700

3,000

765

8,410

3,000

10,500 4,280 Slide 63

EDC, Tomball, TX

Compressive Strength Effect of Confining Stress

Confined

Unconfined

Slide 64

EDC, Tomball, TX

32

Ultimate Confined Compressive Strength

Source – World Oil 1977 Slide 65

EDC, Tomball, TX

Measured Compressive Strength O O

Unconfined Compressive Strength Destructive Test ³ Prepare conditioned slurry in 2 in2 cube molds ³ Cure in curing chamber to BHST ³ Load to failure in hydraulic press at different elapsed times ³ UCS = Force / Area (psi)

Slide 66

EDC, Tomball, TX

33

Measuring Compressive Strength

Slide 67

EDC, Tomball, TX

Ultrasonic Cement Analyzer O O

O O O

Non-destructive test Measures and records the inverse P-wave of velocity through a cement slurry as a function of time Unconfined compressive strength is estimated via an empirical algorithm Continuous read-out Also plots sonic travel time, in order to calculate attenuation time to calibrate cement bond logs Slide 68

EDC, Tomball, TX

34

Ultrasonic Cement Analyzer (cont.)

Slide 69

EDC, Tomball, TX

Ultrasonic Cement Analyzer (cont.)

Slide 70

EDC, Tomball, TX

35

Flexural & Tensile Strength O O O O

Cement slurry prepared and cured in special molds Flexural Strength measured using the lever and fulcrum effect Tensile strength measured by applying tension to shaped mold Recent evidence shows that tensile strength may be more important than compressive strength ³ Ductility, flexibility ³ Stress cycling Slide 71

EDC, Tomball, TX

Flexural & Tensile Strength (cont.)

Slide 72

EDC, Tomball, TX

36


Slide 73

EDC, Tomball, TX


Slide 74

EDC, Tomball, TX

37

Free Fluid O

O

O

Free fluid may separate out and contribute to slurry shrinkage Shrinkage may affect bonding or contribute to gas migration In deviated wellbores, free fluid will float to the high side of the wellbore and create a conductive channel

Slide 75

EDC, Tomball, TX

Free Fluid Test O

O

O

O

Mix and condition slurry to BHCT Pour slurry into 250 mL graduated cylinder Leave static 2 hours at ambient temperature (may be inclined to simulate wellbore) Measure free fluid with a pipette Slide 76

EDC, Tomball, TX

38

Slurry Segregation & Settling O

O

Test measures the ability of the slurry to maintain a stable suspension at downhole conditions Critical for deviated and horizontal wellbores and for gasmigration control slurries

Slide 77

EDC, Tomball, TX

BP Settling Test O

O O

O O O O

Mix and condition slurry to BHCT or 194 °F (90 °C) Transfer to preheated settlement tube Place in curing chamber, ramp to BHCT and maintain until end of test, applying 3,000 psi (21 MPa) After 16 hours, cool to ambient temperature Measure settlement, in mm Break column into 1 inch segments Measure density of each segment by Archimedes method Slide 78

EDC, Tomball, TX

39

BP Settling Test

Slide 79

EDC, Tomball, TX

Gas Migration Testing O

O

O

O

O

Simulates exposure of cement slurry to a high-pressure permeable gas zone and to a lower pressure permeability zone The hydrostatic pressure of the fluid on top of the cement plus the hydrostatic pressure of the unset cement will prevent gas intrusion from occurring During the cement hydration process, the hydrostatic pressure on top of the slurry is relived thus reducing the cement pore pressure As the cement sets, the cement pore pressure may decrease below the gas reservoir pressure. The unbalance of pressures can allow gas to intrude the cement column. The gas can migrate to the well and to the surface and may cause a well blow out or the gas can communicate to a lower pressure permeable zone

Slide 80

EDC, Tomball, TX

40

Gas Flow Model O O

Cement slurry is mixed and conditioned to BHCT Three pressures are applied to the cement slurry during the test ³ Pressurized mineral oil will simulate the hydrostatic pressure of different fluids like drilling mud or cement spacer ³ The gas pressure is applied into cement slurry with nitrogen gas ³ The third pressure is applied with the use of a back pressure regulator to simulate a low-pressure permeable zone

O

Piston movement, fluid filtrate volume and gas filtrate volume and cement pore pressure are measured continuously during the test Slide 81

EDC, Tomball, TX

Slide 82

EDC, Tomball, TX

41

Slide 83

EDC, Tomball, TX

60

1200

50

1000

40

800

30

600

20

400

10

200

0

0 0

250

500

750

Cement Pore Pressure (psi), Gas Volume (cc)

Plunger Distance (mm), Filtrate Volume (cc)

Typical Gas Flow Model Results

Plunger Distance Cement Pore Pressure Filtrate Volume Gas Volume

1000

Elapsed Time (minutes)

Slide 84

EDC, Tomball, TX

42

Density Measurement

Atmospheric Mud Scale

Pressurized Mud Scale Slide 85

EDC, Tomball, TX

Shear Bond Test

Measures hydraulic coupling to steel Slide 86

EDC, Tomball, TX

43

Cement Expansion / Shrinkage

Slide 87

EDC, Tomball, TX

Cement Expansion / Shrinkage (cont.)

Slide 88

EDC, Tomball, TX

44

References O

Cementing Engineering Support Manual ³ CementEngSupport.nsf

O

API Spec 10A ³ Cements and Materials for Well Testing

O

API RP 10B ³ Testing Well Cements

Slide 89

EDC, Tomball, TX

45

ISO 10426-1:2000(E)

Table 1 — Chemical requirements Cement Class A

B

C

D, E, F

G

H

NA

6,0

NA

NA

NA

NA

4,5

NA

NA

NA

ORDINARY GRADE (O) Magnesium oxide (MgO), maximum, %

6,0

Sulfur trioxide (SO3), maximum, %

3,5

a

Loss on ignition, maximum, %

3,0

NA

3,0

NA

NA

NA

Insoluble residue, maximum, %

0,75

NA

0,75

NA

NA

NA

Tricalcium aluminate (C3A), maximum, %

NR

NA

15

NA

NA

NA

Magnesium oxide (MgO), maximum, %

NA

6,0

6,0

6,0

6,0

6,0


NA

3,0

3,5

3,0

3,0

3,0


NA

3,0

3,0

3,0

3,0

3,0


NA

0,75

0,75

0,75

0,75

0,75

Tricalcium silicate (C3S)

NA

NR

NR

NR

58 b

58 b 48 b

MODERATE SULFATE-RESISTANT GRADE (MSR)

maximum, %

NA

NR

NR

NR

48 b

Tricalcium aluminate (C3A), maximum % (3)

NA

8

8

8

8

8

Total alkali content, expressed as sodium oxide (Na2O)

NA

NR

NR

NR

0,75 c

0,75 c

Magnesium oxide (MgO), maximum, %

NA

6,0

6,0

6,0

6,0

6,0


NA

3,0

3,5

3,0

3,0

3,0


NA

3,0

3,0

3,0

3,0

3,0


NA

0,75

0,75

0,75

0,75

0,75 65 b

minimum, %

equivalent, maximum, % HIGH SULFATE-RESISTANT GRADE (HSR)

maximum, %

NA

NR

NR

NR

minimum, %

NA

NR

NR

NR

65 b 48 b

NA

3b

3b

3b

3b

3b

the

NA

24 b

24 b

24 b

24 b

24 b

Total alkali content expressed as sodium oxide (Na2O)

NA

NR

NR

NR

0,75 c

0,75 c

Tricalcium silicate (C3S)

Tricalcium aluminate (C3A), maximum, % Tetracalcium aluminoferrite (C4AF) plus twice tricalcium aluminate (C3A), maximum, %

48 b

equivalent, maximum, % NR = No Requirement; NA = Not Applicable a When the tricalcium aluminate content (expressed as C A) of the cement is 8 % or less, the maximum SO content shall be 3 %. 3 3 b The expressing of chemical limitations by means of calculated assumed compounds does not necessarily mean that the oxides are actually or entirely present as such compounds. When the ratio of the percentages of Al2O3 to Fe2O3 is 0,64 or less, the C3A content is zero. When the Al2O3 to Fe2O3 ratio is greater than 0,64, the compounds shall be calculated as follows: C3A = (2,65 × % Al2O3) – (1,69 × % Fe2O3) C4AF = 3,04 × % Fe2O3 C3S = (4,07 × % CaO) – (7,60 × % SiO2) – (6,72 × % Al2O3) – (1,43 × % Fe2O3) – (2,85 × % SO3) When the ratio of Al2O3 to Fe2O3 is less than 0,64, the C3S shall be calculated as follows: C3S = (4,07 × % CaO) – (7,60 × % SiO2) – (4,48 × % Al2O3) – (2,86 × % Fe2O3) – (2,85 × % SO3) c The sodium oxide equivalent (expressed as Na O equivalent) shall be calculated by the formula: 2 Na2O equivalent = (0,658 × % K2O) + (% Na2O)

6

© ISO 2000 – All rights reserved

ISO 10426-1:2000(E)

Table 2 — Summary of physical and performance requirements Well cement Class

A

B

C

D

E

F

G

H

Mix water, % mass fraction of cement (Table 5)

46

46

56

38

38

38

44

38

Turbidimeter (specified surface, minimum m2/kg)

150

160

220

NR

NR

NR

NR

NR

Air permeability (specified surface, minimum m2/kg)

280

280

400

NR

NR

NR

NR

NR

NR

NR

NR

NR

NR

NR

5,5

5,5

Fineness tests (alternative methods) (clause 6)

Free fluid content, maximum % (clause 8) Compressive strength test

Schedule number,

(8-h curing time) Table 6 (clause 9)

Compressive strength test (24-h curing time) (clause 9)

Final curing temp.

Final curing pressure

°C (°F)

MPa (psi)

Minimum compressive strength MPa (psi)

NA

38 (100)

atm.

1,7 (250)

1,4 (200)

2,1 (300)

NR

NR

NR

2,1 (300)

2,1 (300)

NA

60 (140)

atm.

NR

NR

NR

NR

NR

NR

10,3 (1 500)

10,3 (1 500)

6S

110 (230)

20,7 (3 000)

NR

NR

NR

3,4 (500)

NR

NR

NR

NR

8S

143 (290)

20,7 (3 000)

NR

NR

NR

NR

3,4 (500)

NR

NR

NR

9S

160 (320)

20,7 (3 000)

NR

NR

NR

NR

NR

3,4 (500)

NR

NR

Final curing temp.

Final curing pressure

°C (°F)

MPa (psi)

Schedule number, Table 6

Minimum compressive strength MPa (psi)

NA

38 (100)

Atm.

12,4 (1 800)

10,3 (1 500)

13,8 (2 000)

NR

NR

NR

NR

NR

4S

77 (170)

20,7 (3 000)

NR

NR

NR

6,9 (1 000)

6,9 (1 000)

NR

NR

NR

6S

110 (230)

20,7 (3 000)

NR

NR

NR

13,8 (2 000)

NR

6,9 (1 000)

NR

NR

8S

143 (290)

20,7 (3 000)

NR

NR

NR

NR

13,8 (2 000)

NR

NR

NR

9S

160 (320)

20,7 (3 000)

NR

NR

NR

NR

NR

6,9 (1 000)

NR

NR


7

ISO 10426-1:2000(E)

Table 2 — Summary of physical and performance requirements (continued) Well cement Class Pressure temperature thickening time test (clause 10)

A

Specification test Schedule number Tables 9 through 13

B

C

D

E

F

G

H

Thickening time (min./max.)

Maximum consistency

min

(15 min to 30 min stirring period) Bca

4

30

90 min.

90 min.

90 min.

90 min.

NR

NR

NR

NR

5

30

NR

NR

NR

NR

NR

NR

90 min.

90 min.

5

30

NR

NR

NR

NR

NR

NR

6

30

NR

NR

NR

8

30

NR

NR

NR

NR

154 min.

9

30

NR

NR

NR

NR

NR

100 min. 100 min. 100 min.

120 max. 120 max. NR

NR

NR

NR

NR

190 min.

NR

NR

a Bearden units of consistency (B ) obtained on a pressurized consistometer as defined in clause 10 and calibrated as per the same clause. c

NR = No Requirement

4.2 4.2.1

Sampling frequency, timing of tests and equipment Sampling frequency

For well cement Classes C, D, E, F, G and H, a sample for testing shall be taken by either method (1): over a 24-h interval or method (2): on a 1 000 ton (maximum) production run. For well cement Classes A and B, a sample for testing shall be taken by either method (1): over a 14-day interval or method (2): on a 25 000 ton (maximum) production run. These samples shall represent the product as produced. At the choice of the manufacturer, either method (1) or method (2) may be used. 4.2.2

Time from sampling to testing

Each sample shall be tested for conformance to this part of ISO 10426. All tests shall be completed within seven working days after sampling. 4.2.3

Specified equipment

Equipment used for testing well cements shall comply with Table 3. Dimensions shown in Figures 5, 6, 10 and 11 are for cement specification test equipment manufacturing purposes. Dimensional recertification shall not be required.

8


Cementing Engineering Support © Copyright BJ Services Company 2005 CONFIDENTIAL - Uncontrolled document when printed. Revision No. 0 Revision Date: 01/01/2001 Printed: 01/25/2005

6.0 TEMPERATURE INFORMATION 6.3 Static, Circulating and Squeeze Temperature vs. Depth

Section:

TABLE 2 Static, Circulating and Squeeze Temperature versus Depth Depth 0.9°F/100' 1.0°F/100' 1.1°F/100' 1.2°F/100' TVD BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT FT 500 85 80 80 85 80 80 86 80 80 86 80 80 1000 89 80 80 90 80 80 91 80 80 92 80 80 1500 94 84 82 95 84 83 97 84 84 98 85 86 2000 98 89 86 100 89 87 102 89 89 104 90 90 2500 103 91 89 105 92 91 108 92 93 110 93 95 3000 107 94 93 110 95 95 113 95 97 116 95 100 3500 112 96 96 115 97 99 119 97 102 122 98 105 4000 116 99 100 120 100 10 3124 100 106 128 101 109 4500 121 102 104 125 103 107 130 103 111 134 104 114 5000 125 105 107 130 107 111 135 107 115 140 108 119 5500 130 109 111 135 110 115 141 110 120 146 111 124 6000 134 112 115 140 113 120 146 114 124 152 115 129 6500 139 115 119 145 116 124 152 118 129 158 119 134 7000 143 119 122 150 120 128 157 121 134 164 123 139 7500 148 122 126 155 123 132 163 125 138 170 128 145 8000 152 126 130 160 128 137 168 129 143 176 132 150 8500 157 130 134 165 131 141 174 133 148 182 137 155 9000 161 134 138 170 135 145 179 137 153 188 142 160 9500 166 137 142 175 138 150 185 142 158 194 147 166 10000 170 141 146 180 142 154 190 146 163 200 152 171 10500 175 143 150 185 146 159 196 151 168 206 158 176 11000 179 144 154 190 149 163 201 156 173 212 163 182 11500 184 146 158 195 153 168 207 160 178 218 169 187 12000 188 148 162 200 156 173 212 165 183 224 174 193 12500 193 152 167 201 1161 177 218 170 188 230 180 198 13000 197 156 171 210 165 182 223 175 193 236 185 204 13500 202 160 175 215 170 187 229 180 198 242 191 210 14000 206 164 179 220 175 191 234 185 204 248 196 216 14500 211 168 184 225 180 196 240 191 209 254 202 221 15000 215 173 188 230 184 201 245 196 214 260 208 227 15500 220 177 193 235 189 206 251 202 220 266 214 233 16000 224 182 197 240 194 211 256 207 225 272 220 239 16550 229 186 202 245 200 216 262 213 231 278 226 245 17000 233 191 206 250 205 221 267 219 236 284 233 251 17500 238 196 211 255 210 226 273 225 242 290 239 258 18000 242 201 215 260 216 231 278 231 247 296 246 264 18500 247 206 220 265 221 237 284 237 253 302 252 270 19000 251 211 225 270 227 242 289 243 259 308 259 276 19500 256 216 230 275 233 247 295 250 265 314 266 283

CONFIDENTIAL - Uncontrolled document when printed. Printed: 01/25/2005

© Copyright BJ Services Company 2003 Page: 1

20000

260

222 234 280 239 253 300 256 271 320 Charts derived from API Recommended Practice 10B Dec-97


274

289


TABLE 2 (continued) Static, Circulating and Squeeze Temperature versus Depth Depth 1.3°F/100' 1.4°F/100' 1.5°F/100' 1.6°F/100' TVD BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT FT 500 87 80 80 87 80 80 88 80 80 88 80 80 1000 93 80 80 94 80 80 95 80 80 96 80 80 1500 100 85 87 101 85 88 103 86 89 104 85 90 2000 103 90 92 108 90 93 110 90 95 112 91 97 2500 113 93 97 115 93 99 118 93 101 120 94 103 3000 119 96 102 122 96 105 125 96 107 128 97 109 3500 126 99 107 129 99 110 133 99 113 136 100 116 4000 132 10 1113 136 102 116 140 102 119 144 103 122 4500 139 105 118 143 106 121 148 106 125 152 107 129 5000 145 109 123 150 109 127 155 110 131 160 111 135 5500 152 112 129 157 113 133 163 114 137 168 115 142 6000 158 116 134 164 117 139 170 118 144 176 119 149 6500 165 121 140 171 122 145 178 123 150 184 125 155 7000 171 125 145 178 127 151 185 129 156 192 131 162 7500 178 130 151 185 133 157 192 134 163 200 137 169 8000 184 135 156 192 138 163 200 140 169 208 143 176 8500 191 141 162 199 144 169 208 147 176 216 151 183 9000 197 146 168 206 150 175 215 153 183 224 158 190 9500 204 152 173 213 157 181 223 160 189 232 166 197 10000 210 158 179 220 163 188 230 167 196 240 174 204 10500 217 164 185 227 170 194 238 175 203 248 183 211 11000 223 171 191 234 177 200 245 184 210 256 192 219 11500 230 177 19*7 244 185 207 253 192 216 264 201 226 12000 236 183 203 248 192 213 260 201 223 272 210 237 12500 243 189 209 255 198 220 268 208 230 280 217 241 13000 249 195 215 262 205 226 275 214 237 288 224 249 13500 256 201 221 269 211 233 283 221 245 296 232 256 14000 262 207 228 276 218 240 290 228 252 304 239 264 14500 269 213 234 283 224 247 298 236 259 312 247 272 15000 275 220 240 290 231 253 305 243 266 320 255 280 15500 282 226 247 297 238 260 313 251 274 328 263 287 16000 288 233 253 304 246 267 320 258 281 336 271 295 16550 295 240 260 311 253 274 328 266 289 344 279 304 17000 301 246 266 318 260 281 335 274 297 352 288 312 17500 308 253 273 325 268 289 343 282 304 360 297 320 18000 314 261 280 332 276 296 350 291 312 368 306 328 18500 321 268 287 339 284 303 358 299 320 376 315 337 19000 327 276 293 346 292 311 365 308 328 384 324 345 19500 334 283 300 353 300 318 373 317 336 392 333 354 20000 340 291 307 360 308 326 380 326 344 400 343 362 Charts derived from API Recommended Practice 10B Dec-97



TABLE 2 (continued) Static, Circulating and Squeeze Temperature versus Depth Depth 1.7°F/100' 1.8°F/100' 1.9°F/100' 2.0°F/100' TVD BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT FT 500 89 80 80 89 80 80 90 80 80 90 80 80 1000 97 80 80 98 80 80 99 80 80 100 80 80 1500 106 85 91 107 85 93 109 85 94 110 85 95 2000 114 91 98 116 91 100 118 91 101 125 91 103 2500 123 94 105 125 94 107 128 94 109 130 94 111 3000 131 97 112 134 97 114 137 97 116 140 98 119 3500 140 100 118 143 101 121 147 101 124 150 101 127 4000 148 104 125 152 104 128 155 104 132 160 105 135 4500 157 107 132 161 109 136 166 109 139 170 111 143 5000 165 110 139 170 113 143 175 115 147 180 117 151 5500 174 115 146 179 118 151 185 120 155 190 123 159 6000 182 120 153 188 123 158 194 126 163 200 129 168 6500 191 126 161 197 130 166 204 134 171 210 138 176 7000 199 133 168 206 138 173 213 143 179 220 148 185 7500 208 139 175 215 145 181 223 151 187 230 157 193 8000 216 146 182 224 153 189 232 160 196 240 167 202 8500 225 154 190 233 162 197 242 170 204 250 178 211 9000 233 163 197 242 171 205 251 180 212 260 188 220 9500 242 171 205 251 181 213 261 190 221 270 199 229 10000 250 180 213 260 190 221 270 200 229 280 210 237 10500 259 190 220 269 199 229 280 209 238 290 219 247 11000 267 199 228 278 209 237 289 218 246 300 228 256 11500 276 209 236 287 218 246 299 227 255 310 236 265 12000 284 219 244 296 227 254 308 236 264 320 245 274 12500 293 226 252 305 236 262 318 245 273 330 254 284 13000 301 234 260 314 244 271 327 254 282 340 263 293 13500 310 242 268 323 252 279 337 262 291 350 273 303 14000 318 250 276 332 261 288 346 271 300 360 282 312 14500 327 258 284 341 269 297 356 281 309 370 292 322 15000 335 267 293 350 278 306 365 290 319 380 302 332 15500 344 275 301 359 287 315 375 300 328 390 312 342 16000 352 284 309 368 297 324 384 309 338 400 322 352 16550 361 293 318 377 306 333 394 319 347 410 333 362 17000 369 302 327 386 316 342 403 330 357 420 343 372 17500 378 311 335 395 325 351 413 340 367 430 354 382 18000 386 321 344 404 335 360 422 350 376 440 365 393 18500 395 330 353 413 346 370 432 361 386 450 377 403 19000 403 340 362 422 356 379 441 372 396 460 388 414 19500 412 350 371 431 367 389 451 384 407 470 400 424 20000 420 360 380 440 378 399 460 395 417 480 412 435 Charts derived from API Recommended Practice 10B Dec-97



TABLE 2 (continued) Static, Circulating and Squeeze Temperature versus Depth Depth 2.1°F/100' 2.2°F/100' 2.3°F/100' 2.4°F/100' TVD BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT FT 500 91 80 80 91 80 80 92 80 80 92 80 80 1000 101 83 88 102 83 89 103 83 93 104 83 90 1500 112 88 96 113 89 97 115 90 98 116 92 100 2000 122 94 104 124 96 106 126 98 107 128 99 109 2500 133 99 113 135 101 115 138 104 117 140 106 118 3000 143 104 121 146 107 123 149 110 126 152 114 128 3500 154 109 129 157 113 132 161 117 135 164 121 138 4000 164 114 138 168 119 141 172 124 144 176 129 147 4500 175 120 147 179 126 150 184 131 154 188 137 157 5000 185 127 155 190 133 159 195 139 163 200 145 167 5500 196 133 164 201 140 168 207 147 173 212 153 177 6000 206 140 173 212 147 177 218 155 182 224 162 187 6500 217 149 182 223 156 187 230 163 192 238 171 197 7000 227 158 190 234 165 196 241 173 202 248 180 208 7500 238 166 200 245 174 206 253 181 212 260 189 218 8000 248 175 209 256 183 215 264 191 222 272 199 228 8500 259 185 218 267 193 225 276 201 232 284 208 239 9000 269 195 227 278 203 234 287 211 242 296 218 249 9500 280 205 236 289 213 244 299 221 252 308 228 260 10000 290 215 246 300 223 254 310 231 262 320 239 271 10500 301 227 255 311 234 264 322 242 273 332 249 282 11000 311 236 265 322 244 274 333 252 283 344 260 293 11500 322 245 275 333 253 284 345 262 294 356 270 304 12000 332 254 284 344 263 295 356 272 305 268 281 315 12500 343 264 294 355 273 305 368 282 315 380 292 326 13000 353 273 304 366 283 315 379 293 326 392 303 337 13500 364 283 314 377 293 326 391 304 337 404 314 349 14000 374 293 324 388 304 336 402 314 348 416 325 361 14500 385 303 335 399 314 347 414 326 360 428 337 372 15000 395 314 345 410 325 358 425 337 371 440 349 384 15500 406 324 355 421 336 369 437 349 382 452 361 396 16000 416 335 366 432 348 380 448 360 394 464 373 408 16550 427 346 376 443 359 391 460 373 405 473 386 420 17000 437 357 387 454 371 402 471 385 417 488 399 432 17500 448 369 398 465 383 413 483 397 429 500 412 445 18000 458 380 409 476 395 425 494 410 441 512 425 457 18500 469 392 420 487 408 436 506 423 463 524 439 470 19000 479 405 431 498 421 448 517 437 465 536 453 482 19500 490 417 442 509 434 460 529 450 477 548 467 495 20000 500 430 453 520 447 472 540 464 490 560 482 508 Charts derived from API Recommended Practice 10B Dec-97



TABLE 2 (continued) Static, Circulating and Squeeze Temperature versus Depth Depth 2.5°F/100' 2.6°F/100' 2.7°F/100' 2.8°F/100' TVD BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT BHST BHCT BHSqT FT 500 93 80 80 93 80 80 94 80 80 94 80 80 1000 105 86 90 106 87 91 107 88 92 108 88 92 1500 118 9*3 101 119 94 102 121 95 103 122 96 104 2000 130 101 111 132 102 112 134 103 114 136 105 115 2500 143 109 120 145 110 122 148 112 124 150 114 126 3000 155 117 130 158 119 133 161 121 135 164 123 137 3500 168 125 140 171 128 143 175 130 146 178 132 149 4000 180 134 151 184 136 154 188 139 157 192 141 160 4500 193 142 161 197 145 164 202 148 168 206 151 172 5000 205 151 171 210 154 175 215 158 179 220 161 183 5500 218 160 181 223 163 186 229 167 190 234 171 195 6000 230 169 192 236 173 197 242 177 202 248 181 205 6500 243 178 203 249 182 208 256 187 213 262 191 218 7000 255 187 213 262 192 219 269 197 225 276 202 230 7500 268 197 224 175 202 230 283 207 236 290 212 242 8000 280 206 235 288 212 241 296 217 248 304 223 254 8500 293 216 246 301 222 253 310 228 260 318 234 267 9000 305 226 257 314 232 264 323 239 272 332 245 279 9500 318 236 268 327 243 276 337 250 284 346 256 291 10000 330 246 279 340 254 287 350 261 296 360 268 304 10500 343 257 290 353 265 299 364 272 308 374 280 317 11000 355 268 302 366 276 311 377 284 320 388 292 330 11500 368 279 313 379 287 323 391 295 333 402 304 342 12000 380 290 325 392 298 335 404 307 345 416 316 356 12500 393 301 337 405 310 347 418 320 358 430 329 369 13000 405 312 349 418 322 360 431 332 371 444 342 382 13500 418 324 361 431 334 372 445 345 384 458 355 395 14000 430 336 373 444 347 385 458 357 397 472 368 409 14500 443 348 385 457 359 397 472 371 410 486 382 422 15000 455 361 397 470 372 410 485 384 423 500 396 436 15500 468 373 409 483 385 423 499 398 437 514 410 450 16000 480 386 422 496 399 436 512 412 450 528 424 464 16550 493 399 435 509 412 449 526 426 464 542 439 478 17000 505 413 447 522 426 462 539 440 477 556 454 493 17500 518 426 460 535 441 476 553 455 491 570 469 507 18000 530 440 473 548 455 489 566 470 505 584 485 521 18500 543 454 486 561 470 503 580 486 520 598 501 536 19000 555 469 499 574 485 517 593 501 534 612 517 551 19500 568 484 513 587 507 531 607 517 548 626 534 566 20000 580 499 526 660 516 545 620 534 563 640 551 581 Charts derived from API Recommended Practice 10B Dec-97



TABLE 2 (continued) Static, Circulating and Squeeze Temperature versus Depth Depth TVD FT 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 16550 17000 17500 18000 18500 19000 19500 20000

2.9°F/100' 3.0°/100' BHST BHCT BHSqT BHST BHCT 95 80 80 95 80 109 89 93 110 89 124 97 105 125 98 138 106 117 140 107 153 115 128 155 117 167 125 140 170 127 182 134 151 185 137 196 144 163 200 147 211 154 175 215 157 225 164 187 230 167 240 174 199 245 178 254 185 211 260 189 269 195 224 275 200 283 206 236 290 211 298 217 248 305 222 312 228 261 320 234 327 240 274 335 246 341 251 286 350 258 356 263 299 365 270 370 275 312 380 282 385 287 326 395 295 399 300 339 410 308 414 312 352 425 321 428 325 366 440 334 443 338 379 455 348 457 352 393 470 361 472 365 407 485 375 486 379 421 500 390 501 393 435 515 404 515 407 449 530 419 530 422 464 545 434 544 437 478 560 450 559 452 493 575 466 573 468 508 590 482 588 484 523 605 498 602 500 538 620 515 617 517 553 635 532 631 534 568 650 550 646 551 584 665 568 660 568 599 680 586 Charts derived from API Recommended Practice 10B Dec-97

BHSqT 80 93 107 118 130 142 154 166 179 191 203 216 229 242 254 267 281 294 307 321 334 348 362 376 390 404 418 433 448 462 477 492 507 523 538 554 569 585 601 618

Subtopics 6.1 Temperature 6.2 Discussion of Well Circulation 6.4 API Static Temperatures 6.5 API Casing & Liner Circulating Temperatures 6.6 API Squeeze Temperatures CONFIDENTIAL - Uncontrolled document when printed. Printed: 01/25/2005


Related Topics 1.0 GENERAL INFORMATION 2.0 TEST EQUIPMENT 3.0 LABORATORY EQUIPMENT 4.0 TEST PROCEDURES 5.0 SLURRY PROPERTIES CALCULATIONS 6.0 TEMPERATURE INFORMATION 7.0 RHEOLOGY INFORMATION 8.0 PRODUCT INFORMATION 9.0 CONVERSION FACTORS AND FORMULAS 10.0 GAS FLOW MODEL ASSEMBLY 11.0 HPHT RECOMMENDED PRACTICES



Absolute Volume Calculations Section 10

Printed: 7/21/2006

EDC, Tomball, TX

API Version

Printed: 7/21/2006

EDC, Tomball, TX

1

Bulk Volume O

Bulk Volume ³ Cubic Foot (ft3) Ë Standard unit of bulk volume for cements and cement additives Ë Volume 1 foot long by 1 foot wide by 1 foot tall Ë Also known as a SACK

O

Bulk Density ³ 94 lb/ft3 for API cements ³ Sales unit for cements in the USA is the sack ³ 94 lb/ft3 = 94 lb/sk Slide 3

EDC, Tomball, TX

Absolute Volume O

O

The absolute volume of any material is the volume of the material only, when all of the air has been removed from it In other words, it is the actual volume of the material itself, disregarding the air spaces between the particles, no matter how small the particles ³ For example: wheat flour -- there are still air spaces between the particles

Slide 4

EDC, Tomball, TX

2

Absolute Volume (cont.) O

O

Portland cement is made up of very fine particles, but since the particles are irregularly shaped, there is considerable air space between the particles A sack of Portland cement occupies one cubic foot of bulk volume ³ However, when it is mixed with water, the air comes out of the cement ³ Once the air volume is taken out, what is left is the absolute volume of the cement Slide 5

EDC, Tomball, TX

Absolute Volume O

Absolute Volume ³ One sack or one cubic foot (ft3) of bulk API cement is 94 lb multiplied times the absolute volume factor for API cements in either ft3/lb or gal/lb ³ Absolute volume factors may be found in a table listing the Physical Properties of Cements and Additives, in the Engineering Handbook Ë gal/lb=(1 gal)/[Specific Gravity x Density Water (ppg)] Slide 6

EDC, Tomball, TX

3

Absolute Volume O

O

This absolute or true volume of the cement added to the volume of the mixing water make up the slurry volume We use a special term for this slurry volume called the yield, and is expressed in cubic feet per sack, usually written cf/sk

Slide 7

EDC, Tomball, TX

Absolute Volume O

The Electronic Engineering Handbook, Cementing Section, under Descriptions of API Cements has a table of "Physical Properties of Cements and Additives”

Slide 8

EDC, Tomball, TX

4

Absolute Volume One Sack of API Class G Cement Bulk Volume 1 cuft per 94 lbs Absolute Volume 0.4794 cuft per 94 lbs Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume O

Two columns of absolute volume factors for the various cementing products are found in the table ³ One column gives the absolute volume in gallons per pound or gal/lb ³ The other column shows absolute volume for the same materials in cubic foot per pound, or cf/lb ³ If the cf/lb factor for API cements, 0.0051, is multiplied by 94 lbs per sack, the absolute volume is 0.4794 cf per 94 lb sack Slide 10

EDC, Tomball, TX

5

Slide 11

EDC, Tomball, TX

Absolute Volume O

O

O

A cement slurry is usually designed by working from the density of the drilling fluid in the hole The slurry density typically ranges from 1/2 pound to 1-1/2 pounds per gallon (ppg) heavier (denser) than the drilling mud Additives are then included to give the slurry whatever characteristics are needed for the well conditions Slide 12

EDC, Tomball, TX

6

Density, Mix Water and Yield O

Slurry ³ Liquid resulting from adding water to dry cement or a dry cement blend

O

Neat cement or neat slurry ³ Water and cement without any additives

O

Interrelated Slurry Properties ³ Density ³ Mixing water ³ Yield Slide 13

EDC, Tomball, TX

Slurry Properties O

Density

O

³ Amount of water required to mix one sack of any given cement or cement blend ³ Expressed in gallons per sack (gal/sk).

³ Weight per unit volume of slurry ³ Expressed in pounds per gallon (ppg). O

Yield ³ The absolute volume of the dry cement or blend plus the volume of the mixing water and additives ³ Expressed in cubic feet per sack (ft3/sk).

Mixing Water

O

Mix Fluid ³ Amount of water plus liquid chemicals or dry chemicals predissolved in water ³ Expressed in gallons per sack (gal/sk). Slide 14

EDC, Tomball, TX

7

Density, Mix Water and Yield (cont.) O

Since these three are inter-related, if any one of the three changes, then the other two must also change ³ If the mixing water is decreased, the slurry yield will also go down, but the density will increase.

O

The Engineering Handbook shows the density, mixing water, and yield values for API cements Slide 15

EDC, Tomball, TX

Calculating Additives O

O

Most cement additives are calculated and dry-blended as a percent by weight of cement or cement blend (BWOC) Two exceptions: ³ Sodium Chloride & Potassium Chloride Ë Although frequently dry-blended into the bulk cement, these are calculated as a percent by weight of the mixing water (BWOW)

Slide 16

EDC, Tomball, TX

8


DRY ADDITIVES ³ Usual measure = % BWOC ³ NaCl and KCl = % BWOW ³ Others = lbs/sk

O

LIQUID ADDITIVES ³ Usual measure = gps or gal/sk ³ Low concentrations = ghs or gal/100sacks

Slide 17

EDC, Tomball, TX

Calculating Additives Example #1 O

Calculate the pounds of cement, and retarder which would make up one sack of Class G + 0.3% R-3 94 lb = lb of API Class G cement per sk 0.003 X 94 lb = 0.282 lb of R-3 per sk

Slide 18

EDC, Tomball, TX

9


Calculate the pounds of fly ash, cement, bentonite (gel), and retarder which would make up one sack of 35:65:6 + 0.2% R-3 0.35 X 74 lb = 25.9 lb of Fly Ash 0.65 X 94 lb = 61.1 lb of API cement (Class ?) 87.0 lb / sk of Blend 0.06 X 87 lb = 5.22 lb of Bentonite 0.002 X 87 lb = 0.174 lb of R-3 Slide 19

EDC, Tomball, TX


Calculate the pounds of cement, and salt which would make up one sack of Class H + 10% Salt + 46% Water (5.18 gal/sk) 94 lb = lb of API Class G cement per sk 46% X 94 lb = 43.24 lb of Water per sk 10% X 43.24 lb = 4.324 lb Salt per sk

or 5.18 gal /sk X 8.34 lb/gal = 43.2 lb of Water / sk 10% X 43.2 lb = 4.32 lb Salt per sk Slide 20

EDC, Tomball, TX

10

Calculating Additives (cont) O

O

Offshore, liquid additives are added to the mixing water, in place of dry-blending dry additives into the bulk cement, for logistic reasons Liquid additives are usually added in gal/100 sks or gal/sk

Slide 21

EDC, Tomball, TX

Absolute Volume Calculations O

Once a slurry density is decided upon, the mixing water, in gallons per sack, and the yield, in cubic feet per sack, are calculated ³ These calculations include not only the water volume and the absolute volume of the cement, but also the absolute volume of other additives in the slurry

Slide 22

EDC, Tomball, TX

11


O

O

An exception to this is gel, which should always be included, no matter how low the percentage Laboratory and PowerVision computer programs do the calculations quickly and accurately, including all additives regardless of concentration The mixing water and yield values are then supplied to the cement crew going on the job

Slide 23

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Class G cement mixed at 15.8 lb/gal

Printed: 7/21/2006

EDC, Tomball, TX

12

Absolute Volume Calculations Example #1 Step 1 (mass balance for one sack) Component

Amount

lb/cuft

lb

gal/lb

gal

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 1 (mass balance for one sack) Component Class G

Amount 100%

lb/cuft 94.0

lb

gal/lb

gal

Printed: 7/21/2006

EDC, Tomball, TX

13


Amount 100%

lb/cuft 94.0

lb 94.0000

gal/lb

gal

Printed: 7/21/2006

EDC, Tomball, TX


Amount 100%

lb/cuft 94.0

lb 94.0000

x

gal/lb 0.0382

gal

Printed: 7/21/2006

EDC, Tomball, TX

14


Amount 100%

lb/cuft 94.0

lb 94.0000

x

gal/lb gal 0.0382 = 3.5908

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 1 (mass balance for one sack) Component Class G Subtotal

Amount 100%

lb/cuft 94.0

lb 94.0000 94.0000

x

gal/lb gal 0.0382 = 3.5908 3.5908

Printed: 7/21/2006

EDC, Tomball, TX

15

Absolute Volume Calculations Example #1 Step 1 (mass balance for one sack) Component Class G Subtotal Water

Amount 100%

lb/cuft 94.0

lb 94.0000 94.0000 W

x

gal/lb gal 0.0382 = 3.5908 3.5908

Printed: 7/21/2006

EDC, Tomball, TX


Amount 100%

lb/cuft 94.0

lb 94.0000 94.0000 W

x x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199

Printed: 7/21/2006

EDC, Tomball, TX

16


Amount 100%

lb/cuft 94.0

lb 94.0000 94.0000 W

x x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199 = 0.1199W

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 1 (mass balance for one sack) Component Class G Subtotal Water Totals

Amount 100%

lb/cuft 94.0

lb 94.0000 94.0000 W

x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199 = 0.1199W

94.0000 + W

3.5908 + 0.1199W

x

Printed: 7/21/2006

EDC, Tomball, TX

17

Absolute Volume Calculations Example #1 Step 1 (mass balance for one sack) Component Class G Subtotal Water Totals

Amount 100%

lb/cuft 94.0

lb 94.0000 94.0000 W

x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199 = 0.1199W

94.0000 + W

3.5908 + 0.1199W

94.0000 + W 3.5908 + 0.1199W

x

= 15.8 ppg

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 2 (solve for unknown) 94.0000 + W 3.5908 + 0.1199W

= 15.8 ppg

Printed: 7/21/2006

EDC, Tomball, TX

18


= 15.8 ppg

94.0000 + W = 15.8 (3.5908 + 0.1199W)

Printed: 7/21/2006

EDC, Tomball, TX


= 15.8 ppg

94.0000 + W = 15.8 (3.5908 + 0.1199W) 94.0000 + W = 56.7346 + 1.8944W

Printed: 7/21/2006

EDC, Tomball, TX

19


= 15.8 ppg

94.0000 + W = 15.8 (3.5908 + 0.1199W) 94.0000 + W = 56.7346 + 1.8944W 94.0000 - 56.7346 = 1.8944W - W

Printed: 7/21/2006

EDC, Tomball, TX


= 15.8 ppg

94.0000 + W = 15.8 (3.5908 + 0.1199W) 94.0000 + W = 56.7346 + 1.8944W 94.0000 - 56.7346 = 1.8944W - W 37.2654 = 0.8944W

Printed: 7/21/2006

EDC, Tomball, TX

20


= 15.8 ppg

94.0000 + W = 15.8 (3.5908 + 0.1199W) 94.0000 + W = 56.7346 + 1.8944W 94.0000 - 56.7346 = 1.8944W - W 37.2654 = 0.8944W W = 37.2654 / 0.8944

Printed: 7/21/2006

EDC, Tomball, TX


= 15.8 ppg

94.0000 + W = 15.8 (3.5908 + 0.1199W) 94.0000 + W = 56.7346 + 1.8944W 94.0000 - 56.7346 = 1.8944W - W 37.2654 = 0.8944W W = 37.2654 / 0.8944 W = 41.6653 lb Printed: 7/21/2006

EDC, Tomball, TX

21

Absolute Volume Calculations Example #1 Step 3 (substitute for unknown) W = 41.6653 Component Class G Subtotal Water

Amount lb/cuft 100% 94.0

lb 94.0000 94.0000 W

x x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199 = 0.1199W

Totals

Printed: 7/21/2006

EDC, Tomball, TX



lb 94.0000 94.0000 41.6653

x x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199 = 4.9957

Totals

Printed: 7/21/2006

EDC, Tomball, TX

22



Totals

lb 94.0000 94.0000 41.6653

x x

gal/lb gal 0.0382 = 3.5908 3.5908 0.1199 = 4.9957

135.6653

8.5865

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 4 (solve as required)

• Mix water = ?.?? gal/sack

Printed: 7/21/2006

EDC, Tomball, TX

23


• Mix water = 5.00 gal/sack

Printed: 7/21/2006

EDC, Tomball, TX


• Mix water = 5.00 gal/sack • Yield = ?.??? cuft/sack

Printed: 7/21/2006

EDC, Tomball, TX

24


• Mix water = 5.00 gal/sack • Yield = 8.5865 gal/sack

Printed: 7/21/2006

EDC, Tomball, TX


• Mix water = 5.00 gal/sack • Yield = 8.5865 gal / 7.4808 gal/cuft = ?.??? cuft/sack

Factor Printed: 7/21/2006

EDC, Tomball, TX

25


• Mix water = 5.00 gal/sack • Yield = 8.5865 gal / 7.4808 gal/cuft = 1.148 cuft/sack

Printed: 7/21/2006

EDC, Tomball, TX


• Mix water = 5.00 gal/sack • Yield = 8.5865 gal / 7.4808 gal/cuft = 1.148 cuft/sack • Weight check = ??.?? ppg

Printed: 7/21/2006

EDC, Tomball, TX

26


• Mix water = 5.00 gal/sack • Yield = 8.5865 gal / 7.4808 gal/cuft = 1.148 cuft/sack • Weight check = 135.6653 lb / 8.5865 gal = 15.80 ppg

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations

Now it is your turn!

Example #2 Class G with 8% Bentonite mixed at 13.3 lb/gal

Printed: 7/21/2006

EDC, Tomball, TX

27

That would be your first!

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #3

You have one more to do!

35:65:4 Class H with 5% Salt mixed at 12.8 lb/gal

Printed: 7/21/2006

EDC, Tomball, TX

28

Absolute Volume Calculations Other Additive Units and Measures DRY ADDITIVES Usual measure = % BWOC NaCl and KCl = % BWOW Others = lbs/sk LIQUID ADDITIVES Usual measure = gps or gal/sk Low concentrations = ghs or gal/100sacks Ex.

Component Class H Celloflake A-3L

Amount lb/cuft 100% 94.0 1/2 #/sk 0.05 gps

lb 94.0000 0.5000 0.5841

x x x

gal/lb gal 0.0382 = 2.3340 0.0844 = 0.0422 0.0856 = 0.0500

Printed: 7/21/2006

EDC, Tomball, TX


Printed: 7/21/2006

EDC, Tomball, TX

29

Bulk Volume O

Bulk Volume (m3) ³ The total volume including pore space occupied by a material ³ The bulk volume of one tonne of Portland cement is 0.694 m3

Slide 94

EDC, Tomball, TX

Absolute Volume O

O

The absolute volume of any material is the volume of the material only, when all of the air has been removed from it In other words, it is the actual volume of the material itself, disregarding the air spaces between the particles, no matter how small the particles ³ For example: wheat flour -- there are still air spaces between the particles

Slide 95

EDC, Tomball, TX

30

Absolute Volume (cont.) O

O

Portland cement is made up of very fine particles, but since the particles are irregularly shaped, there is considerable air space between the particles The absolute volume of one tonne of Portland cement is 0.3175 m3

Slide 96

EDC, Tomball, TX

Absolute Volume O

The Electronic Engineering Handbook, Cementing Section, under Descriptions of Cements has a table of "Physical Properties of Cements and Additives”

Slide 97

EDC, Tomball, TX

31

Slide 98

EDC, Tomball, TX

Absolute Volume O

The Electronic Engineering Handbook, Cementing Section, under Descriptions of Canadian Cements has a table of "Physical Properties of Canadian Cements and Additives”

Slide 99

EDC, Tomball, TX

32

Slide 100

EDC, Tomball, TX

Absolute Volume O

O

O

A cement slurry is usually designed by working from the density of the drilling fluid in the hole The slurry density typically ranges from 50 to 200 kg/m3 heavier (denser) than the drilling mud Additives are then included to give the slurry whatever characteristics are needed for the well conditions Slide 101

EDC, Tomball, TX

33

Density, Mix Water and Yield O

Slurry ³ Liquid resulting from adding water to dry cement or a dry cement blend

O

Neat cement or neat slurry ³ Water and cement without any additives

O

Interrelated Slurry Properties ³ Density ³ Mixing water ³ Yield Slide 102

EDC, Tomball, TX

Slurry Properties O

Density

O

³ Weight per unit volume of slurry ³ Expressed in kg/m3 O

³ Amount of water required to mix one tonne of any given cement or cement blend ³ Expressed in m3/tonne

Yield ³ The absolute volume of the dry cement or blend plus the volume of the mixing water ³ Expressed in m3/tonne

Mixing Water

O

Mix Fluid ³ Amount of water plus liquid chemicals or dry chemicals predissolved in water ³ Expressed in m3/tonne Slide 103

EDC, Tomball, TX

34

Density, Mix Water and Yield (cont.) O

Since these three are inter-related, if any one of the three changes, then the other two must also change ³ If the mixing water is decreased, the slurry yield will also go down, but the density will increase.

O

The Engineering Handbook shows the density, mixing water, and yield values for API cements Slide 104

EDC, Tomball, TX


O

Most cement additives are calculated and dry-blended as a percent by weight of cement or cement blend (BWOC) Two exceptions: ³ Sodium Chloride & Potassium Chloride Ë Although frequently dry-blended into the bulk cement, these are calculated as a percent by weight of the mixing water (BWOW)

Slide 105

EDC, Tomball, TX

35


DRY ADDITIVES ³ Usual measure = % BWOC ³ NaCl and KCl = % BWOW ³ Others = kg/tonne

O

LIQUID ADDITIVES ³ Usual measure = litres/tonne

Slide 106

EDC, Tomball, TX


Calculate the amount of cement and retarder for one tonne of Class G + 0.3% R-3 Class G R-3 Total

= .003 X 1000 kg

= 1000.0 kg = 3.0 kg = 1003.0 kg

Slide 107

EDC, Tomball, TX

36


Calculate the amount of fly ash, cement, bentonite (gel), and dispersant which would make up one tonne of 1:1:2 + 0.5% CD-31. Note: 1:1:2 Cement is composed of 1 part (absolute volume) of fly ash plus 1 part (absolute volume) of cement and 2% bentonite gel.

Slide 108

EDC, Tomball, TX

Calculating Additives Example #2 (cont.) O

Procedure to determine cement and fly ash for 1:1:2 blend.

For one tonne of blend: y = fly ash z = cement y + z = 1000 kg

Slide 109

EDC, Tomball, TX

37

Calculating Additives Example #2 (cont.) For equal absolute volumes of cement and fly ash: y x 0.4545 m3/t = z x 0.3175 m3/t

Solving for y and z gives: y = 411 kg fly ash z = 589 kg cement

Slide 110

EDC, Tomball, TX

Calculating Additives Example #2 (cont.) 1:1:0 Cement Blend

(1/S.G.) m3/(m3/t) Absolute Volume Base on Blend Factor 1 m3 of Weight S.G. m3/t tonnes blend m3 Poz 2.20 0.4545 50% 0.5000 1.1000 Canadian Cement 3.15 0.3175 50% 0.5000 1.5750 Blend Calculations ==> 1.0000 2.6750

(tonnes of Component ÷ tonnes of Blend)

Base on 1 tonne of blend 0.41121 tonnes 0.58879 tonnes 1.0000 tonnes

Blend Calculations ==> 0.3738 m3/t 2.675 t/m3

Slide 111

EDC, Tomball, TX

38

Calculating Additives Example #2 (cont.) O

SOLUTION Fly Ash = 411 kg Cement = 589 kg TOTAL = 1000 kg Bentonite = 0.02 x 1000 kg = 20 kg CD-31 = 0.005 x 1000 kg = 5 kg

Slide 112

EDC, Tomball, TX


Calculate the amount of cement, and salt which would make up one tonne of Class G + 10% Salt + 44% water ³ Remember: Salt (NaCl) is based on weight of Water, not Cement Class G Water NaCl salt

= 44% x 1000 kg = 10% x 440 kg/t

= 1000 kg = 440 kg = 44 kg

Slide 113

EDC, Tomball, TX

39

Calculating Additives (cont) O

O

Offshore, liquid additives are added to the mixing water, in place of dry-blending dry additives into the bulk cement, for logistic reasons Liquid additives are usually added in litres/tonne (l/t)

Slide 114

EDC, Tomball, TX


Once a slurry density is decided upon, the mixing water, in m3/t, and the yield, in m3/t, are calculated ³ These calculations include not only the water volume and the absolute volume of the cement, but also the absolute volume of other additives in the slurry

Slide 115

EDC, Tomball, TX

40


O

Laboratory, PowerVision computer programs do the calculations quickly and accurately, including all additives regardless of concentration The mixing water and yield values are then supplied to the cement crew going on the job

Slide 116

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Determine the density and yield for Class G cement mixed at the recommended water rates. Minimum Water requirement for Class G = 44% BWOP (by weight of product) Printed: 7/21/2006

EDC, Tomball, TX

41

Absolute Volume Calculations Example #1 Step 1 (mass balance) Component

Amount kg

Abs vol yield m3/t

m3

water kg/t

water yield m3

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 1 (mass balance) Component Class G

Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t

water yield m3

Printed: 7/21/2006

EDC, Tomball, TX

42

Absolute Volume Calculations Example #1 Step 1 (mass balance) Component Class G

Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t 440

water yield m3 0.440

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1 Step 2 (yield calculation) Component Class G

Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t 440


Yield = Total volume per tonne

Printed: 7/21/2006

EDC, Tomball, TX

43


Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t 440


Yield = Total volume per tonne = volume product + volume water

Printed: 7/21/2006

EDC, Tomball, TX


Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t 440


Yield = Total volume per tonne = volume product + volume water = 0.3175 m3 + 0.440 m3 Yield = 0.758 m3/t

Printed: 7/21/2006

EDC, Tomball, TX

44

Absolute Volume Calculations Example #1 Step 3 (density calculation) Component Class G

Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water

water yield m3

kg/t 440

0.440

Density = total weight / total volume

Printed: 7/21/2006

EDC, Tomball, TX


Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t 440


Density = total weight / total volume = weight product + weight water volume product + volume water

Printed: 7/21/2006

EDC, Tomball, TX

45


Amount

Abs vol yield

kg

m3/t

m3

1000

0.3175

0.3175

water kg/t 440


Density = total weight / total volume = weight product + weight water volume product + volume water = 1000 kg + 440 kg 0.3175 m3 + 0.440 m3 Density = 1901 kg/m3 Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1a Determine the water and yield if the density changes to 1300 kg/m3

Printed: 7/21/2006

EDC, Tomball, TX

46

Absolute Volume Calculations Example #1a Step 1 (calculate water req’d) Density = Total wt = 1300 kg/m3 Total vol

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1a Step 1 (calculate water req’d) = 1300 kg/m3 Density = Total wt Total vol = wt prod + wt water = 1300 kg/m3 vol prod + vol water

Printed: 7/21/2006

EDC, Tomball, TX

47

Absolute Volume Calculations Example #1a Step 1 (calculate water req’d) = 1300 kg/m3 Density = Total wt Total vol = wt prod + wt water = 1300 kg/m3 vol prod + vol water = 1000 kg + W(wt) kg = 1300 kg/m3 3 3 0.3175 m + W(vol) m

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1a Step 1 (calculate water req’d) NOTE : W(wt) = W(vol) x 1000 kg/m3

Printed: 7/21/2006

EDC, Tomball, TX

48

Absolute Volume Calculations Example #1a Step 1 (calculate water req’d) NOTE : W(wt) = W(vol) x 1000 kg/m3 Density = 1000 + 1000W(vol) = 1300 kg/m3 0.3175 + W(vol) W(vol) = 1.9575 m3 or 1.958 m3/t

Printed: 7/21/2006

EDC, Tomball, TX

Absolute Volume Calculations Example #1a Step 2 (determine yield) Yield

= Total volume / tonne = vol prod + vol water = 0.3175 m3 + 1.9575 m3

Yield

= 2.275 m3 or 2.275 m3/t

Printed: 7/21/2006

EDC, Tomball, TX

49


Now it is your turn!

Determine the recommended yield, density and water requirements for a 1:1:2 Class G blend with 0.5% CD-31 Minimum Water requirement for Class G = 44% BWOP, Poz = 46% BWOP, Bentonite = 530% BWOP Printed: 7/21/2006

EDC, Tomball, TX

That would be your first!

Printed: 7/21/2006

EDC, Tomball, TX

50


You have one more to do!

Calculate the normal yield, density and water for a 0:1:0 Class “G” blend with 18% Salt (NaCl)

Printed: 7/21/2006

EDC, Tomball, TX

That’s all there is to it!

Printed: 7/21/2006

EDC, Tomball, TX

51

~

n

PHYSICAL PROPERTIES OF CEMENT AND CEMENTING ADDITIVES

COMPONENT Cement "A" Cement "G" Nowpoz Gel Salt Gel Silica Flour(SFA) Cement Fondue Firebrick Gilsonite Barite Hematite N.S.2000 N.S.7000 Gyp-cem Mica Cello flake Sand (SFS) Calcium Chloride Water Diatomaceous Earth Anthralite Anthrabridge Sodium Chloride (%B.W.O.w.) 5% 10% 15% 18% 20% 25% 30% 35% 37% (Sa!.)

WATER ABSOLUTE SPECIFIC REQUIREMENTBULKOENSllY VOLUME GRAVllY tlm3 m31t kg/t 3.15 460 1.44 0.3175 3.15 440 1.44 0.3175 2.20 460 1.12 0.4545 2.60 5300 0.96 0.3846 2.50 5300 0.95 0.4000 2.63 285 1.12 0.3802 3.23 400 1.44 0.3096 2.60 1.335 0.3846 395 1.07 333 0.80 0.9346 4.23 220 2.16 0.2364 5.02 30 3.09 0.1992 0.37 1750 0.24 2.7027 0.70 650 0.40 1.4286 2.70 400 1.20 0.3704 2.87 0.32 0.3484 1.3/1.4 .4 .721.76 2.63 1.720 0.3802 1.96 0.81 0.5102 1.00 1.00 1.0000 2.00 1.30 1.30 2.165

29.2-63.8 450 333 -

0.17 0.786 0.741

0.5000 0.7692 0.7692

n

(\

n

(\,

n

f\

f\

1.407 0.3067 0.3201 0.3316 0.3377 0.3413 0.3492 0.3552 0.3594 0.3606

n

n

~

n

n

PROPERTIES OF A 1 TONNE CEMENT SYSTEM

BLEND 0:1:0 "A" 0:1:0"G"

POZZOlAN CEMENT GEL WATER YIELD OENSllY m'lt m'lt kg kglm' Ibfgal kg kg 0 1000 0 0.460 0.777 1878 15.7 0 0.440 0.757 1901 15.9 0 1000

0:1:2" 0:1:4" 0:1:8" 0:1:12" 0:1:16"

0 0 0 0 0

1000 1000 1000 1000 1000

20 40 80 120 160

0.546 0.652 0.864 1.076 1.288

0.871 0.985 1.212 1.439 1.666

1798 1719 1604 1526 1470

15.0 14.3 13.4 12.7 12.3

0:1:2" 0:1:4"" 0:1:8"" 0:1:12" 0:1:16"

0 0 0 0 0

1000 1000 1000 1000 1 000

20 40 80 120 160

0.580 0.720 1.000 1.280 1.560

0.905 1.053 1.348 1.643 1.938

1768 1672 1543 1461 1404

14.8 14.0 12.9 12.2 11.7

1:1:0 1:1:1 1:1:2 1:1:4 1:1:6 1:1:8 1:1:12

411 411 411 411 411 411 411

589 589 589 589 589 589 589

0 10 20 40 60 80 120

0.448 0.501 0.554 0.660 0.766 0.872 1.084

0.822 0.879 0.936 1.049 1.163 1.276 1.503

1762 1720 1683 1621 1571 1530 1466

14.7 14.4 14.0 13.5 13.1 12.8 12.2

2:1:0 2:1:2 2:1:4 2:1:6 2:1:8

583 583 583 583 583

417 417 417 417 417

0 20 40 60 80

0.452 0.558 0.664 0.770 0.876

0.849 0.963 1.076 1.190 1.303

1710 1639 1583 1538 1501

14.3 13.7 13.2 12.8 12.5

2:1:12 2:1:16

583 583

417 417

120 160

1.088 1.300

1.530 1.757

1443 1400

12.0 11.7

NOTE: The above properties are based on optimum water for Class "G" cement, however they can also be used for Class "A" cement. " Water requirements "" Water requirements

using 530% by weight of gel (Normal Yield) using 700% by weight of gel (High Yield)

DRY BLEND BULK VOLUMES 0:1:0

= 0.694

m'lt

OF:

+ (.010 m'lt

x % gel)

= 0.776

m'lt + (.010 m'lt x % gel) 2:1:0 = 0.810 m'lt + (.010 m'lt x % gel) 1:1:0

BJServicesCompany Canada@1983 (9-83)

232

233

BJ ServicesCompany Canada@ 1983 (9-83)

Wj

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PROPERTIES OF NOWSCO SALT CEMENTS % SALT BYWT.WAlER 10 15 18 37

SALT kg/t 44 66 79 163

WAlER m'lt 0.440 0.440 0.440 0.440

YIELD m'ft 0.772 0.780 0.785 0.818

DENSITY kg/m' Iblgal 1922 16.0 1931 16.1 1936 16.2 1960 16.4

0:1:4

10 15 18 37

65 98 117 241

0.652 0.652 0.652 0.652

1.006 1.018 1.025 1.074

1747 1759 1765 1800

14.6 14.7 14.7 15.0

0:1:8

10 15 18 37

86 130 156 320

0.864 0.864 0.864 0.864

1.240 1.255 1.265 1.330

1637 1652 1660 1702

13.7 13.8 13.9 14.2

1:1:0

10 15 18 37

45 67 81 166

0.448 0.448 0.448 0.448

0.837 0.845 0.850 0.884

1784 1794 1799 1827

14.9 15.0 15.0 15.2

1:1:2

10 15 18 37

55 83 100 205

0.554 0.554 0.554 0.554

0.954 0.964 0.970 1.012

1709 1720 1726 1759

14.3 14.4 14.4 14.7

2:1:8

10 15 18 37

88 131 158 324

0.876 0.876 0.876 0.876

1.332 1.348 1.357 1.423

1534 1549 1557 1602

12.8 12.9 13.0 13.4

BLEND 0:1:0

NOTE: The above properties are based on optimum water for Class "G" Cement.

PROPERTIESOF NOWSCO SCAVENGERSLURRIES BLEND" 0:1:0 0:1:0 0:1:0 0:1:0 0:1:0 0:1:0 0:1:0

WAlER m'/t

YIELD m'lt

3.130 2.328 1.829 1.488 1.241

3.447

1.053 0.906

2.646 2.146 1.806 1.558 1.371 1.223

DENSITY kg/m' 1198 1258 1318 1378 1438 1498 1558

Ibfgal 10.0 10.5 11.0 11.5 12.0 12.5 13.0

Wj

n

PROPERTIES OF NOWSCO WHIPSTOCK PLUGS

SLURRY

n

(\

n

n

(,

('I

T-ID SALT WATER YIELD DENSITY m'/t m'/t % kg/m' Ib/gal kg 0.427 0.744 1917 16.0 10 10 0.381 0.699 1977 16.5 10 0.341 0.658 2037 17.0 10 0.305 0.622 2097 17.5

20% Sand

833 833 833

167 167 167

8 8 8

-

0.368 0.328 0.298

0.696 0.656 0.626

1965 2025 2073

16.4 16.9 17.3

30% Sand

769 769 769

231 231 231

7 7 7

-

0.344 0.312 0.277

0.675 0.644 0.609

1989 2037 2097

16.6 17.0 17.5

34% Sand

746 746 746 746

254 254 254 254

6.6 6.6 6.6 6.6

-

0.341 0.309 0.274 0.249

0.674 0.643 0.608 0.582

1989 2037 2097 2145

16.6 17.0 17.5 17.9

{\

('II

nl.f\

Neat

CEMENTSAND kg kg 1000 1000 1000 1000

Salt

1000 1000 1000 1000

-

10 10 10 10

5 10 15 18

0.427 0.427 0.427 0.427

0.751 0.758 0.766 0.771

1927 1938 1946 1951

16.1 16.2 16.2 16.3

1000 1000 1000 1000

-

10 10 10 10

5 10 15 18

0.381 0.381 0.381 0.381

0.705 0.711 0.718 0.722

1987 1996 2004 2008

16.6 16.7 16.7 16.8

1000 1000 1000 1000

-

10 10 10 10

5 10 15 18

0.341 0.341 0.341 0.341

0.664 0.670 0.676 0.680

2045 2053 2060 2064

17.1 17.1 17.2 17.2

1000 1000 1000 1000

-

10 10 10 10

5 10 15 18

0.305 0.305 0.305 0.305

0.627 0.632 0.638 0.641

2104 2112 2117 2120

17.6 17.6 17.7 17.7

I

'Valid for either Class "A" or Class "G"

BJ Services Company Canada@ 19B3 (9-B3)

234

235

BJ Services Company Canada@ 1983 (9-83)

Pressure and Force Calculations Section 11

Printed: 7/21/2006

EDC, Tomball, TX

API Version

Printed: 7/21/2006

EDC, Tomball, TX

1

Pressures and Forces O

Hydrostatic pressure

O

Differential pressure

O

Force, Pressure, and Area

O

Buoyancy Slide 3

EDC, Tomball, TX

Hydrostatic Pressure O

Hydrostatic pressure, also sometimes called hydrostatic head or hydrostatic head pressure, is abbreviated as Ph or, less often, as HH.

Slide 4

EDC, Tomball, TX

2


The formula for calculating Ph

Ph = 0.052 x TVD x ρ ³ Ph ³ TVD ³ ρ

= Hydrostatic Pressure, psi = True Vertical Depth, ft = Fluid Density, ppg

¸ Shape and volume do not affect Ph. Slide 5

EDC, Tomball, TX

MD=2000 feet

TVD=1000 feet Slide 6

EDC, Tomball, TX

3

Practice Problems Hydrostatic Pressure What is the hydrostatic pressure at a depth of 3,824'?

3,824'

What is the hydrostatic pressure at a depth of 7,648'?

11.8 ppg

7,648'

Slide 7

EDC, Tomball, TX

Find Ph at TD 8.43 #/gal 2% KCl to 3050’

8.96 #/gal 15% HCl to 6300’

11.5 #/gal mud to 7350’ Slide 9

EDC, Tomball, TX

4

Find Ph at TD

Fresh water to 1500’ 2% KCl to 2000’ 14.8# cement to 3500’ 11# mud to 4000’ 2% KCl to 4200’ Slide 11

EDC, Tomball, TX

Differential Pressure

O

Differential pressure, ∆ P ³ Pronounced "delta p” ³ Difference between two separate pressures.

O

In casing cementing ³ ∆ P is the difference between two separate hydrostatic pressures ³ Occurs when two columns of fluid with different densities are in communication with one another

Slide 13

EDC, Tomball, TX

5

Differential Pressure O

Pressure to “bump the plug” ³∆ P Ë Differential pressure at the plug depth Ë Ph inside the casing vs Ph in the annulus ¸ At the same depth

Ë Appears as surface pressure ¸ Pump pressure

Formula

∆ P = PhAnnulus - PhCasing Slide 14

EDC, Tomball, TX

2% KCl @ 8.43 ppg inside 10 ppg mud outside 1000 feet

O

∆P = Ph (outside) - Ph (inside)

Slide 15

EDC, Tomball, TX

6

11 ppg mud Top of lead @ 3050’ 8.34 ppg water 12.8 ppg lead Calculate ∆P Top of tail @ 7500’ 14.8 ppg tail Shoe @ 7800’

Slide 17

EDC, Tomball, TX

10# mud 5-1/2”, 15.5# csg to 12,250 feet.

6000’ 6750’

11# spacer

12.8# lead 11750’

14.8# tail 12210’ 12250’

1. Calculate ∆P to bump the plug. 2. Calculate displacement in barrels. Slide 19

EDC, Tomball, TX

7

Force, Pressure, and Area (F-P-A) O

O

O

O

FORCE is the total pounds of mass exerted over a specific surface area. Force is expressed in pounds and always has a direction. PRESSURE is the amount of force exerted over a unit area. Fluid pressure is exerted in all directions. Pressure is expressed in pounds per square inch or psi. AREA is the total surface over which force is exerted. Area is expressed in square inches. Formula to calculate F-P-A: F = P x A. Therefore, ³ P = F/A, and ³ A = F/P Slide 22

EDC, Tomball, TX

F-P-A O

O

Some problems require that we calculate the area of a circle from a known diameter. The formula for calculating the area of a circle is: ³ Acircle = pi x radius squared or ³ Acircle = π x r2

O

Since in the oil field we work with diameters instead of radii, we have rearranged the formula to solve for the area of a circle from a known diameter: Acircle = d2 x 0.7854 Slide 23

EDC, Tomball, TX

8

PRACTICE PROBLEMS

F-P-A Acircle = d2 x 0.7854 What is the surface area of the end of a pump plunger which has an outside diameter of 4 inches?

Slide 24

EDC, Tomball, TX

F-P-A What is the maximum pressure at which you can pump with the same pump, if the maximum force which can be applied to the power end is 150,000 pounds?

F P A

Slide 26

EDC, Tomball, TX

9

Calculating Forces on Casing Why are upwards, and downwards forces on the casing important? Does friction pressure, and rates have anything to do with these pressures? What happens if your upward force exceeds your downward force? Slide 28

EDC, Tomball, TX

Calculating Forces on Casing (worst case while pumping) O

Force Down is equal to the weight of the pipe plus the weight of the fluid inside down to the deepest flotation device.

O

Force Up is equal to 1.0 times the depth times the cross sectional area of the casing OD.

³ Wt of fluid = HH to the deepest flotation device X area of casing ID

³ Since the magnitude of the induced annular friction pressure cannot be estimated for all situations a worst case scenario of an annular pressure equivalent to 1.0 psi/ft gradient at TD is assumed. Pressures above this would not be expected since adjacent formations would likely be fractured. O

If upward force ≥ downward force…….. …….CHAIN DOWN THE CASING! Slide 29

EDC, Tomball, TX

10

Calculating Forces on Casing Example While Pumping 8-5/8” 24 lb/ft casing 12¼” open hole Fresh Water (8.34 ppg) Cement (15.9 ppg) Float Shoe @ 200 feet O O

O

Force Up = casing length X area of casing OD X 1.0 psi/ft Force down = HH to deepest flotation device X area of casing ID + casing weight for total casing length If the upward force ≥ downward force ==> chain down casing!

Slide 30

EDC, Tomball, TX

Calculating Forces on Casing (static conditions) O

O

O

Force Down is equal to the weight of the pipe plus the weight of the fluid inside down to the deepest flotation device. Force Up is equal to the annular hydrostatic head at casing TD times the cross sectional area of the pipe (metal only) plus the annular hydrostatic head gradient (assumed to be constant based on input HH and TD) times the depth to the deepest flotation device time the cross sectional area of the casing ID. If upward force ≥ downward force…….. …….CHAIN DOWN THE CASING! Slide 33

EDC, Tomball, TX

11

Calculating Forces on Casing Example Static Conditions 8-5/8” 24 lb/ft casing 12¼” open hole Fresh Water (8.34 ppg) Cement (15.9 ppg) Float Shoe @ 200 feet O

O

O

Force up = HH at TD x metal area + HH at deepest floatation device X area of casing ID Force down = HH to deepest flotation device X area of casing ID + casing weight for total casing length If the upward force ≥ downward force ==> chain down casing!

Slide 34

EDC, Tomball, TX

Buoyancy O

O

The apparent weight of steel pipe suspended open-ended in fluid is the weight of the pipe in air multiplied by a buoyancy factor. The following formula is for calculating a buoyancy factor: lbL (in liquid) = lbA (in air) X [1 - (0.01529 X ppg)] ³ Casing run with a float device and/or guide shoe is calculated the same as open-ended casing. Slide 37

EDC, Tomball, TX

12

Buoyancy (cont.) O

Equation: ³ lbL(in liquid) = lbA(in air) X [1 - (0.01529 X PPG)]

O

What is the air weight of 1,000 ft of 8-5/8” 24 lb/ft casing?

O

What is the apparent weight of this string in 11.2 ppg Mud?

Slide 38

EDC, Tomball, TX


Printed: 7/21/2006

EDC, Tomball, TX

13

Pressures and Forces O

Hydrostatic pressure

O

Differential pressure

O

Force, Pressure, and Area

O

Buoyancy Slide 42

EDC, Tomball, TX


Hydrostatic pressure, also sometimes called hydrostatic head or hydrostatic head pressure, is abbreviated as Ph or, less often, as HH.

Slide 43

EDC, Tomball, TX

14


The formula for calculating Ph

Ph = 9.81 x TVD x s.g. ³ Ph ³ TVD ³ s.g.

= Hydrostatic Pressure, kPa = True Vertical Depth, m = Fluid Specific Gravity

¸ Shape and volume do not affect Ph. Slide 44

EDC, Tomball, TX

MD=2000 m

TVD=1000 m Slide 45

EDC, Tomball, TX

15

Practice Problems Hydrostatic Pressure What is the hydrostatic pressure at a depth of 1165 m?

1165 m

What is the hydrostatic pressure at a depth of 2300 m?

1400 kg/m3

2300 m Slide 46

EDC, Tomball, TX

Find Ph at TD 1011 kg/m3 2% KCl to 930 m

1075 kg/m3 15% HCl to 1920 m

1380 kg/m3 mud to 2240 m Slide 48

EDC, Tomball, TX

16

Find Ph at TD

Fresh water to 500 m 2% KCl to 600 m 1901 kg/m3 cement to 1000 m 1300 kg/m3 mud to 1200 m 2% KCl to 1300 m Slide 50

EDC, Tomball, TX


Differential pressure, ∆ P ³ Pronounced "delta p” ³ Difference between two separate pressures.

O

In casing cementing ³ ∆ P is the difference between two separate hydrostatic pressures ³ Occurs when two columns of fluid with different densities are in communication with one another

Slide 52

EDC, Tomball, TX

17


Pressure to “bump the plug” ³∆ P Ë Differential pressure at the plug depth Ë Ph inside the casing vs Ph in the annulus ¸ At the same depth

Ë Appears as surface pressure ¸ Pump pressure

Formula

∆ P = PhAnnulus - PhCasing Slide 53

EDC, Tomball, TX

2% KCl @ 1011 kg/m3 inside

300 m

O

1200 kg/m3 mud outside ∆P = Ph (outside) - Ph (inside)

Slide 54

EDC, Tomball, TX

18

1320 kg/m3 mud Top of lead @ 930 m 1000 kg/m water 1621 kg/m3 lead Calculate ∆P Top of tail @ 2300 m 1901 kg/m3 ppg tail Shoe @ 2400 m

Slide 56

EDC, Tomball, TX

1190 kg/m3 mud 1800 m 2050 m

139.7 mm csg 23.07 kg/m to 3750 m 1300kg/m3 spacer

1500 kg/m3 lead 3550 m

1901 kg/m3 tail 3737 m 3750 m

1. Calculate ∆P to bump the plug. 2. Calculate displacement in barrels. Slide 58

EDC, Tomball, TX

19

Force, Pressure, and Area (F-P-A) O

O

O

O

FORCE is the total pounds of mass exerted over a specific surface area. Force is expressed in Newtons and always has a direction. PRESSURE is the amount of force exerted over a unit area. Fluid pressure is exerted in all directions. Pressure is expressed in pascals or Pa. AREA is the total surface over which force is exerted. Area is expressed in square meters. Formula to calculate F-P-A: F = P x A. Therefore, ³ P = F/A, and ³ A = F/P Slide 61

EDC, Tomball, TX

F-P-A O

O

Some problems require that we calculate the area of a circle from a known diameter. The formula for calculating the area of a circle is: ³ Acircle = pi x radius squared or ³ Acircle = π x r2

O

Since in the oil field we work with diameters instead of radii, we have rearranged the formula to solve for the area of a circle from a known diameter: Acircle = d2 x 0.7854 Slide 62

EDC, Tomball, TX

20

PRACTICE PROBLEMS

F-P-A Acircle = d2 x 0.7854 What is the surface area of the end of a pump plunger which has an outside diameter of 101.6 mm?

Slide 63

EDC, Tomball, TX

F-P-A O

What is the maximum pressure at which you can pump with the same pump, if the maximum force which can be applied to the power end is 70,000 daN? F

P A

Slide 65

EDC, Tomball, TX

21

Calculating Forces on Casing Why are upwards, and downwards forces on the casing important? Does friction pressure, and rates have anything to do with these pressures? What happens if your upward force exceeds your downward force? Slide 67

EDC, Tomball, TX

Calculating Forces on Casing (worst case while pumping) O

Force Down is equal to the weight of the pipe to TD plus the weight of the fluid inside down to the deepest flotation device. ³ Wt of Fluid = HH to the deepest flotation device (Pa) X area of csg ID (m2)

O

Force Up is equal to the maximum pressure gradient (22.6 kPa/m) times the depth (m) times the cross sectional area (m2) of the casing OD. ³ Since the magnitude of the induced annular friction pressure cannot be estimated for all situations, a worst case scenario of an annular pressure equivalent to 22.6 kPa/m (1.0 psi/ft) gradient at TD is assumed. Pressures above this would not be expected since adjacent formations would likely be fractured.

O

If upward force ≥ downward force…….. …….CHAIN DOWN THE CASING! Slide 68

EDC, Tomball, TX

22

Calculating Forces on Casing Example While Pumping 219.1 mm 35.72 kg/m casing 308.0 mm open hole Fresh Water (1000 kg/m3) Cement (1901 kg/m3) Float Shoe @ 70 m O O

O

Force Up = casing length X area of casing OD X 22.6 kPa/m Force down = (Casing HH to deepest flotation device X area of casing ID) + (casing weight for total casing length) If the upward force ≥ downward force ==> chain down casing!

Slide 69

EDC, Tomball, TX

Calculating Forces on Casing (static conditions) O

O

Force Down is equal to the weight of the pipe to TD plus the weight of the fluid inside down to the deepest flotation device. Force Up is equal to the weight of the displaced fluid in the annulus. Wt of fluid=HH to deepest flotation device (Pa) X area of casing OD (m2).

O

If upward force ≥ downward force…….. …….CHAIN DOWN THE CASING!

Slide 72

EDC, Tomball, TX

23

Calculating Forces on Casing Example Static Conditions 219.1 mm 35.72 kg/m casing 308.0 mm open hole Fresh Water (1000 kg/m3) Cement (1901 kg/m3) Float Shoe @ 70 m O

O

O

Force up = (Annular HH at TD x metal area) + (Annular HH at deepest flotation device X area of casing ID) Force down = (Casing HH to deepest flotation device X area of casing ID) + (casing weight for total casing length) If the upward force ≥ downward force ==> chain down casing!

Slide 73

EDC, Tomball, TX

Buoyancy O

O

The apparent weight of steel pipe suspended open-ended in fluid is the weight of the pipe in air multiplied by a buoyancy factor. The following formula is for calculating a buoyancy factor: daNL (in liquid) = daNA (in air) X [1 - (0.0001276 X kg/m3)]

³ Casing run with a float device and/or guide shoe is calculated the same as open-ended casing. Slide 76

EDC, Tomball, TX

24

Buoyancy (cont.) O

Equation: ³ daNL(in liquid) = daNA(in air) X [1 - (0.0001276 X kg/m3)]

O

What is the air weight of 300 m of 219.1 mm 35.72 kg/m casing?

O

What is the apparent weight of this string in 1350 kg/m3 Mud?

Slide 77

EDC, Tomball, TX

25

Plug Cementing Section 12

Printed: 6/10/2006

EDC, Tomball, TX

Plugback Cementing O O

Introduction Reasons for plugging a well ³ Plug to Abandon the well ³ Whipstocking ³ Lost circulation ³ Abandon a zone ³ Shut off water flow into well ³ Protect a lower (pay) zone ³ Provide bottom for drill stem test

Revised 01/13/2004

Slide 2

EDC, Tomball, TX

1

Plugback Cementing (cont.) O

Plugging Methods ³ Balanced Plug ³ Two-plug method ³ Dump bailer ³ Cement retainer

O

More specifics on balanced plugs

Revised 01/13/2004

Slide 3

EDC, Tomball, TX

Introduction O

Plugback cementing ³ Placing cement slurry at some particular depth in the well and allowing it to set ³ Hydraulic Seal Ë No migration of fluids, liquids or gases Ë Hold pressure from below Ë Hold pressure and pipe weight from above

³ Hold pipe weight from above ³ Sometimes referred to as “Plug Cementing”

Revised 01/13/2004

Slide 4

EDC, Tomball, TX

2

Reasons for Plugging a Well O

Plug to Abandon (PTA, P&A) ³ Reason for most plugs Ë New well is not commercially feasible Ë Old wells, depleted

³ Number and position of plugs usually determined by state or country regulations

Revised 01/13/2004

Slide 5

EDC, Tomball, TX

Reasons for Plugging a Well O

Whipstocking (Sidetracking, Kickoff Plug) ³ Plugs are set to deviate a hole due to: Ë Ë Ë Ë

Directional problems Junk in hole (fish) Multi-lateral well Exploratory borehole for horizontal well Ë Did not find target zone

Revised 01/13/2004

Slide 6

EDC, Tomball, TX

3

Reasons for Plugging a Well (cont.) O

Lost Circulation ³ Cement plugs are set to stop lost circulation problems. They are drilled through to continue drilling deeper to complete the well.

O

Abandon a zone ³ Depleted zones are plugged and production continued above the depleted zones. Sometimes a zone is temporarily plugged and later reopened.

Revised 01/13/2004

Slide 7

EDC, Tomball, TX


Shut off water flow into well ³ Unwanted water flowing into the wellbore from a formation can be a major problem when drilling or producing a well. Plugs are set to seal the formation, then drilled through.

O

Protect a lower pay zone ³ Temporary plugs are set above a potential pay zone while other operations are performed up the hole. The plugs are later drilled out.

Revised 01/13/2004

Slide 8

EDC, Tomball, TX

4


Provide bottom for open hole drill stem test (DST) ³ If a test is to be done 100s of feet (or meters) or more off bottom, a plug is set up the hole to provide a temporary bottom to use to operate the test tools.

Revised 01/13/2004

Slide 9

EDC, Tomball, TX

Plugging Methods O

Balanced plug method ³ Most popular method ³ Probably the best method Ë Economical

³ Slurry is balanced ³ Water pads or spacers also balanced

Revised 01/13/2004

Slide 10

EDC, Tomball, TX

5

Setting a Balanced Plug in Open Hole

At the Balance Point

After Pulling Out

Revised 01/13/2004

Slide 11

EDC, Tomball, TX

Setting a Balanced Plug in Cased Hole


After Pulling Out

Revised 01/13/2004

Slide 12

EDC, Tomball, TX

6

Setting a Balanced Plug Half in and Half Out (50/50)

Height WSI Height WSO


After Pulling Out

Revised 01/13/2004

Slide 13

EDC, Tomball, TX

More Specifics on Balanced Plugs (cont.) O

Plug length (height) usually 200 to 300 ft (60 to 100 m) ³ Rare: less than 50 ft (30 m) or more than 500 ft (150 m)

O

Procedure: Pump pad ahead, cement slurry, pad behind, displace ³ Both pads must be same height ³ Cement must be same height inside and outside DP

Revised 01/13/2004

Slide 14

EDC, Tomball, TX

7

More Specifics on Balanced Plugs (cont.) O

Bottom of the plug can become unstable ³ Deviated wells ³ High density differences

O

Solutions

O

³ “Careful” placement ³ Viscous pills ³ Parabow Link to Parabow animation

Revised 01/13/2004

Slide 15

EDC, Tomball, TX

Plugging Methods: Two-Plug Method O

Two-Plug method ³ Used offshore ³ Uses tool called plug catcher ("plug cutter") ³ Run 2 rubber wiper plugs, 1 ahead & 1 behind Ë Or 1 rubber plug, after cement

³ All cement can be pumped out of work string ³ Often run with tail pipe Ë Reduced diameter or aluminum

Revised 01/13/2004

Slide 16

EDC, Tomball, TX

8

Plugging Methods: Dump Bailer ODump

Bailer Method Wireline Mud/Brine

³Small slurry volumes run on slick line and dumped ³Slow process, shallow work, but cheap (no rig)

Casing/Tubing Dump Bailer Cement Slurry Electrical/Mechanical Dump Release Bridge Plug

Revised 01/13/2004

Slide 17

EDC, Tomball, TX

Plugging Methods: Cement Retainer O

Cement retainer ³ Cased hole only, cement through drillable packer ³ Best way to plug casing, but relatively expensive

Revised 01/13/2004

Slide 18

EDC, Tomball, TX

9

API Version

Printed: 6/10/2006

EDC, Tomball, TX

Calculating a Balanced Plug 2 7/8” 6.5# Tubing 5½” 15.5# Casing Final Plug Depths 50’ Water Spacer 4,950 ft - Top 5,000 ft 4” Open Hole 5,050 ft - Bottom Revised 01/13/2004

Slide 20

EDC, Tomball, TX

10




After Pulling Out

Revised 01/13/2004

Slide 21

EDC, Tomball, TX

Balanced Plug Calculations Step 1: Slurry Volume

Given: Cement Plug 50’ in and 50’ out 50’ Water Spacer on top of plug Slurry Volume: 50 ft in 4.0” O.H. 50 ft X 0.0155 bbl/ft = 0.78 bbls 50 ft in 4.95” ID Casing 50 ft X 0.0238 bbls/ft = 1.19 bbls Total ==> 1.97 bbls Revised 01/13/2004

Slurry

Slide 22

EDC, Tomball, TX

11

Balanced Plug Calculations Step 2: Water Volume

Given: Cement Plug 50’ in and 50’ out 50’ Water Spacer on top of plug Water Volume: 50 ft in 4.95” ID Casing 50 ft X 0.0238 bbls/ft = 1.19 bbls

Water

Revised 01/13/2004

Slide 23

EDC, Tomball, TX

Balanced Plug Calculations O

Step 3: Top of Slurry WSI Slurry in OH Section: 50 ft of 2 7/8” X 4.0” Annulus 50 ft of 2 7/8” 6.5#/ft Tubing

A: 50 X 0.0075 bbl/ft = 0.375 bbls T: 50 X 0.0058 bbl/ft = 0.290 bbls Volume in Open Hole Section 0.665 bbls Revised 01/13/2004

OH Slurry Slide 24

EDC, Tomball, TX

12

Balanced Plug Calculations Step 3: Top of Slurry WSI Slurry in Cased Hole Section:

O

Total - O.H. Section = Cased Hole 1.97 bbls - 0.665 bbls = 1.305 bbls Cased Hole Slurry

Revised 01/13/2004

Slide 25

EDC, Tomball, TX

Balanced Plug Calculations Step 3: Top of Slurry WSI O

Height of Slurry in Cased Hole

Annulus: 2 7/8” X 5½” 15.5#/ft Tubing: 2 7/8” 6.5#/ft Annulus Factor = 0.0158 bbl/ft Tubing Factor = 0.0058 bbl/ft Total Factor = 0.0216 bbl/ft

Cased Hole Slurry

Height of Slurry 1.305 bbls ÷ 0.0216 bbl/ft = 60.4 ft Revised 01/13/2004

Slide 26

EDC, Tomball, TX

13

Balanced Plug Calculations Step 3: Top of Slurry WSI Top of Slurry WSI

O

Top of Slurry = Bottom of Plug - Open Hole Coverage - Cased Hole Coverage 5,050 ft - 50 ft - 60.4 ft = 4,939.6 ft

Cased Hole Slurry

Revised 01/13/2004

Slide 27

EDC, Tomball, TX

Balanced Plug Calculations Step 4: Top of Water WSI O

Height of Water WSI

Annulus: 2 7/8” X 5½” 15.5#/ft Tubing: 2 7/8” 6.5#/ft Annulus Factor = 0.0158 bbl/ft Tubing Factor = 0.0058 bbl/ft Total Factor = 0.0216 bbl/ft

Water

Height of Water 1.19 bbls ÷ 0.0216 bbl/ft = 55.1 ft Revised 01/13/2004

Slide 28

EDC, Tomball, TX

14


Top of Water WSI

Top of Water = Top of Slurry - Height of Water Water

4,939.6 ft - 55.1 ft = 4,884.5 ft This is the Displacement Depth

Revised 01/13/2004

Slide 29

EDC, Tomball, TX

Balanced Plug Calculations Step 5: Water Ahead and Behind Height of Water = 55.1 ft Annulus Factor = 0.0158 bbl/ft Tubing Factor = 0.0058 bbl/ft Ahead Cement (in Annulus): 55.1 ft X 0.0158 bbl/ft = 0.87 bbls Water Behind Cement (in Tubing): 55.1 ft X 0.0058 bbl/ft = 0.32 bbl Water

Water

0.32 bbl + 0.87 bbl = 1.19 bbl Total Revised 01/13/2004

Slide 30

EDC, Tomball, TX

15

Balanced Plug Calculations Step 6: Displacement Volume O

Displacement Volume WSI Displacement

Displacement Volume = Top of Water x Tubing Volume Factor 4,884.5 ft X 0.0058 bbl/ft = 28.33 bbl

Revised 01/13/2004

Slide 31

EDC, Tomball, TX

Calculating a Balanced Plug (cont.) 2 7/8” 6.5# Tubing 5½” 15.5# Casing Depths w/Tubing on Bottom Top of Water = 4,884.5 ft 4,939.6 ft - Top 5,000 ft 4” Open Hole 5,050 ft - Bottom Revised 01/13/2004

Slide 32

EDC, Tomball, TX

16

Balanced Plug Calculations: Step 8 O

Final Pumping Schedule: 1) Pump 0.87 bbls Water ahead 2) Pump 1.97 bbls Cement Slurry 3) Pump 0.32 bbls Water behind 4) Pump 28.33 bbls Displacement

Revised 01/13/2004

Slide 33

EDC, Tomball, TX

Calculating a Balanced Plug: Final Result 2 7/8” 6.5# Tubing 5½” 15.5# Casing Final Plug Depths 50’ Water Spacer 4,950 ft - Top 5,000 ft 4” Open Hole 5,050 ft - Bottom Revised 01/13/2004

Slide 34

EDC, Tomball, TX

17

Calculating a Balanced Plug: eEHB

Repeat with eEHB

Revised 01/13/2004

Slide 35

EDC, Tomball, TX


Printed: 6/10/2006

EDC, Tomball, TX

18

Calculating a Balanced Plug 73.0 mm 9.67 kg/m Tubing 139.7 mm 23.07 kg/m Casing Final Plug Depths 20 m Water Spacer 1,480 m - Top 1,500 m 101.6 mm Open Hole 1,520 m - Bottom Revised 01/13/2004

Slide 39

EDC, Tomball, TX




After Pulling Out

Revised 01/13/2004

Slide 40

EDC, Tomball, TX

19

Balanced Plug Calculations Step 1: Slurry Volume

Given: Cement Plug 20 m in and 20 m out 20 m Water Spacer on top of plug Slurry Volume: 20 m in 101.6 mm O.H. 20 m X 0.008107 m3/m = 0.162 m3 20 m in 125.7 mm ID Casing 20 m X 0.012416 m3/m = 0.248 m3 Total ==> 0.410 m3

Slurry

Revised 01/13/2004

Slide 41

EDC, Tomball, TX

Balanced Plug Calculations Step 2: Water Volume

Given: Cement Plug 20 m in and 20 m out 20 m Water Spacer on top of plug Water Volume: 20 m in 125.7 mm ID Casing 20 m X 0.012416 m3/m = 0.248 m3

Revised 01/13/2004

Water

Slide 42

EDC, Tomball, TX

20


Step 3: Top of Slurry WSI Slurry in OH Section: 20 m of 73.0 mm X 101.3 mm Annulus 20 m of 73.0 mm 9.67 kg/m Tubing

A: 20 X 0.003919 m3/m = 0.078 m3 T: 20 X 0.003019 m3/m = 0.060 m3 Volume in Open Hole Section 0.138 m3

OH Slurry

Revised 01/13/2004

Slide 43

EDC, Tomball, TX


Step 3: Top of Slurry WSI Slurry in Cased Hole Section: Total - O.H. Section = Cased Hole

0.410 m3 – 0.138 m3 = 0.272 m3 Cased Hole Slurry

Revised 01/13/2004

Slide 44

EDC, Tomball, TX

21


Step 3: Top of Slurry WSI Height of Slurry in Cased Hole

Annulus: Tubing:

73.0 mm X 139.7 mm 23.07 kg/m 73.0 mm 9.67 kg/m

Annulus Factor = 0.008227 m3/m Tubing Factor = 0.003019 m3/m Total Factor = 0.011246 m3/m

Cased Hole Slurry

Height of Slurry 0.272 m3 ÷ 0.011246 m3/m = 24.19 m Revised 01/13/2004

Slide 45

EDC, Tomball, TX


Step 3: Top of Slurry WSI Top of Slurry WSI Top of Slurry = Bottom of Plug - Open Hole Coverage - Cased Hole Coverage 1,520 m – 20 m – 24.19 m = 1,475.81 m

Revised 01/13/2004

Cased Hole Slurry

Slide 46

EDC, Tomball, TX

22


Step 4: Top of Water WSI Height of Water WSI Annulus: Tubing:

73.0 mm X 139.7 mm 23.07 kg/m 73.0 mm 9.67 kg/m

Annulus Factor = 0.008227 m3/m Tubing Factor = 0.003019 m3/m Total Factor = 0.011246 m3/m

Water

Height of Water 0.248 m3 ÷ 0.011246 m3/m = 22.05 m

Revised 01/13/2004

Slide 47

EDC, Tomball, TX


Top of Water WSI

Top of Water = Top of Slurry - Height of Water Water

1,475.81 m – 22.05 m = 1,453.76 m This is the Displacement Depth

Revised 01/13/2004

Slide 48

EDC, Tomball, TX

23

Balanced Plug Calculations Step 5: Water Ahead and Behind Height of Water = 22.05 m Annulus Factor = 0.008227 m3/m Tubing Factor = 0.003019 m3/m Ahead Cement (in Annulus): 22.05 m X 0.008227 m3/m = 0.18 m3 Water Behind Cement (in Tubing): 22.05 m X 0.003019 m3/m = 0.07 m3 Water

Water

0.18 m3 + 0.07 m3 = 0.25 m3 Total Revised 01/13/2004

Slide 49

EDC, Tomball, TX

Balanced Plug Calculations Step 6: Displacement Volume O

Displacement Volume WSI Displacement

Displacement Volume = Top of Water x Tubing Volume Factor 1,453.76 m X 0.003019 m3/m = 4.39 m3

Revised 01/13/2004

Slide 50

EDC, Tomball, TX

24

Calculating a Balanced Plug (cont.) 73.0 mm 9.67 kg/m Tubing 139.7 mm 23.07 kg/m Casing Depths w/Tubing on Bottom Top of Water = 1,453.76 m 1,475.8 m - Top 1,500 m 101.6 mm Open Hole 1,520 m - Bottom Revised 01/13/2004

Slide 51

EDC, Tomball, TX

Balanced Plug Calculations: Step 8 O

Final Pumping Schedule: 1) Pump 0.18 m3 Water ahead 2) Pump 0.41 m3 Cement Slurry 3) Pump 0.07 m3 Water behind 4) Pump 4.39 m3 Displacement

Revised 01/13/2004

Slide 52

EDC, Tomball, TX

25

Calculating a Balanced Plug: Final Result 73.0 mm 9.67 kg/m Tubing 139.7 mm 23.07 kg/m Casing Final Plug Depths 20 m Water Spacer 1,480 m - Top 1,500 m 101.6 mm Open Hole 1,520 m - Bottom Revised 01/13/2004

Slide 53

EDC, Tomball, TX

Calculating a Balanced Plug: eEHB

Repeat with eEHB

Revised 01/13/2004

Slide 54

EDC, Tomball, TX

26

Review of Balanced Plugs O O O

Mud system must be in balance Mud contamination cause of most failures Neat, densified, dispersed slurries ³ Sand often added (questionable benefit)

O

Place with open-ended drill pipe or tubing ³ Not advisable to set plugs through drill bit

O

May be set in open or cased hole

Revised 01/13/2004

Slide 57

EDC, Tomball, TX

27

Squeeze Cementing Section 13

Printed: 6/10/2006

EDC, Tomball, TX

Overview Squeeze Cementing O

O O

If Primary Cementing can be considered a science Squeeze cementing is more an art Squeeze cementing depends heavily on: Experience in the field you are working in Experience and skill levels of whomever is operating the mixing equipment Either or both of these factors can make the difference. Slide 2

EDC, Tomball, TX

1

Squeeze Cementing O O O O O O O O O

Definitions Objective Terminology High vs Low Pressure Types of Squeezes Reasons for Squeezing Squeeze cements Placement techniques Tools Slide 3

EDC, Tomball, TX

Squeeze Cementing (Squeezing): Defined O

Squeezing Process of applying hydraulic pressure to force cement slurry to a specific point in a well, and the application of pressure to dehydrate the slurry either in formation voids or against a porous and permeable zone. through perforations through unintended leaks or holes in pipe in open hole.

Slide 4

EDC, Tomball, TX

2

Cement Dehydration: Defined O

O

A cement slurry is composed basically of cement particles and water The particles of "regular"* cement are too large to enter the permeability of the formation

* "Ultra-fine" cement particles are small enough to enter the permeability.

Slide 5

EDC, Tomball, TX

Cement Dehydration Defined (cont.) O

O O

O

Particles are separated from the water under a differential pressure This process is called dehydration Filter cake of solid particles forms on the face of the formation If excessive pressure is exerted, the formation will fracture and some slurry will be forced into the fracture(s) during the squeeze job Slide 6

EDC, Tomball, TX

3

Objective of a Squeeze O

Obtain a pressure fluid seal: Between the casing and the formation filling all the perforations, fractures, or channels behind the casing with cement

or Of the formation filling voids, fractures, and unconsolidated formations with cement to prevent the influx of fluids into the wellbore, or to stop the loss of fluids in the well to a "thief zone".

Slide 7

EDC, Tomball, TX

Squeeze Terminology O

Breakdown Pressure Pressure required to "break down" or fracture the formation, to do a high pressure squeeze.

O

Pump-in Pressure Pressure above pore and below frac pressure at which fluid pumps into formation for low pressure squeeze.

Slide 8

EDC, Tomball, TX

4

Squeeze Terminology (cont.) O

Injection Rate Rate at which a high pressure squeeze job may be started, following breakdown, or Rate at which the formation will take fluid below frac pressure, to do a low pressure squeeze job.

O

Fracture Gradient Psi/foot of depth required to fracture the formation.

Slide 9

EDC, Tomball, TX


Bottomhole Treating Pressure (BHTP) Pressure exerted on formation during a squeeze, it is the sum of the surface treating pressure (STP) plus hydrostatic pressure, minus friction pressure.

O

Hesitation Method With some cement in formation, pumping is stopped for a few minutes, off and on, while displacing.

Slide 10

EDC, Tomball, TX

5


"Running" Squeeze Final squeeze pressure reached during continuous pumping, with not all of cement out in formation.

Slide 11

EDC, Tomball, TX

High Pressure Squeezes O

Process Formation is broken down (fractured) Cement slurry is pumped into the fracture(s) until a particular surface pressure is reached and maintained This pressure is usually decided on by operator beforehand.

Slide 12

EDC, Tomball, TX

6

High Pressure Squeezes (cont.) O

Advantages Enlarges small channels Allows better penetration of perforations

O

Disadvantages Uses more cement than low pressure work Fracture location/orientation uncontrolled

Slide 13

EDC, Tomball, TX

High Pressure Squeezes (cont.) O

Applications Mud in the hole Small single zone No void to fill Need large volume of slurry pumped into zone

Slide 14

EDC, Tomball, TX

7

Low Pressure Squeezes O

Process An injection rate is established that allows sufficient time to get the cement mixed and pumped to the formation without exceeding the BHFP. In extreme cases in shallow wells with small volumes, this rate may be as little as one half barrel per minute or less.

Slide 15

EDC, Tomball, TX

Low Pressure Squeezes (cont.) O

Advantages Uses less cement Does not make natural fractures worse

O

Disadvantages Large displacement volumes take too long Cement doesn't go as deep into formation

Slide 16

EDC, Tomball, TX

8

Low Pressure Squeezes (cont.) O

Applications Squeezing a pay zone Voids to be filled Low BHP wells Low permeability zone Naturally fractured formation

Slide 17

EDC, Tomball, TX

Notes on Squeeze Pressures O

Historically - high pressure squeeze final squeeze pressure relatively high 7,000 psi (50 MPa) is not unheard of

O O

Did not guarantee success Low Pressure Squeeze now more common

Slide 18

EDC, Tomball, TX

9

Types of Squeezes O O O O O

Perforation squeezes Top of liner squeezes Casing leak squeezes Shoe squeezes Open hole squeezes

Slide 19

EDC, Tomball, TX

Types of Squeezes (cont.) O

Perforation squeeze Repair faulty primary cement job Channeling Annular voids from insufficient fill

Exclude formation water from a zone Temporary abandon a productive zone Permanently abandon a play-out zone Isolate a zone -- a “block squeeze”

Slide 20

EDC, Tomball, TX

10


Top of liner squeeze Shut off annular gas flow Between top of liner and upper casing

Repair faulty primary cement job Channeling Inadequate fill

Slide 21

EDC, Tomball, TX


Casing leak squeezes Repair parted casing or split joints Repair holes caused by corrosion

Slide 22

EDC, Tomball, TX

11


Shoe squeezes Over-displacement of primary cement Channeled cement Casing set in weak unconsolidated sands

Slide 23

EDC, Tomball, TX


Open hole squeezes Curing lost circulation problems (out-go) Shut off water, oil, or gas flow into the well (influx) -- “kill squeeze”

Slide 24

EDC, Tomball, TX

12

Squeeze Cements O

Most perforation squeezing is done with either class H or class G, depending on where it occurs Many operators like to densify the cement Fluid Loss Control is recommended

Slide 25

EDC, Tomball, TX

Squeeze Cements (cont.) O

Lighter slurries are used for lost circulation squeezes For the major lost circulation problems, it is common to use a so-called "gunk" squeeze; this can be any one of several variations on cement with diesel oil instead of mixing water Flow Guard-L can also be used half liquid sodium silicate and half water, pumped in sequence with fresh water spacers to contact calcium chloride water downhole, but not before.

Slide 26

EDC, Tomball, TX

13

Squeeze Cements (cont.) O

In the last twenty-five years, there has been an ever-increasing use of fluid loss additives in squeeze cements, especially in perforation and casing leak squeezes Following are some examples of the various applications of high fluid loss cement (with little or no fluid loss additive) and low fluid loss cement (with a significant amount of fluid loss additive).

Slide 27

EDC, Tomball, TX

High Fluid-Loss Squeeze Cement O

Do’s: Dehydrate rapidly Set up close to the wellbore Cause nodes in the casing at the perforations

O

Don’ts: Penetrate well into fracs, etc. Seal Fractures Long channels Long perforated intervals. Slide 28

EDC, Tomball, TX

14

Low Fluid-Loss Squeeze Cement* O

Do’s: dehydrate very slowly penetrate all available routes seal better and further from the wellbore

O

Don’ts: form thick filter cakes form appreciable nodes in perforations

* From 50 to 150 cc/30 minutes is considered good fluid loss control. Slide 29

EDC, Tomball, TX

Low Fluid-Loss Squeeze Cement Cement Node

Primary Cement

Formation

Dehydrated Cement

Casing

Slide 30

EDC, Tomball, TX

15

Placement Techniques Bradenhead Squeeze PSI ON ANNULUS

Bullhead Squeeze Spot Squeeze Slide 31

EDC, Tomball, TX

Placement Techniques (cont.) O

Without a tool Bradenhead squeeze Open-ended work string even with bottom perf Spot cement like balanced plug Pull up out of cement, close annulus at surface Displace

Slide 32

EDC, Tomball, TX

16


With tool(s) Bullhead squeeze Set packer, pressure up back side Pump in Mix cement Displace

Spot squeeze Circulate cement down near end of work string Catch returns on annular ("back") side Close tool, trap annular pressure Displace Slide 33

EDC, Tomball, TX


With tool(s) (cont.) "Circulating" squeeze Set tool between two sets of perfs Circulate slurry out bottom set, back in top set Cement ("plant") work string and tool in hole

Slide 34

EDC, Tomball, TX

17

Squeeze Tools Section 14

Printed: 6/10/2006

EDC, Tomball, TX

Squeeze Tools O O

Why use Squeeze Tools? Types of Squeeze Tools ³ Retrievable Ë Weight Set Packers Ë Tension Set Packers Ë Retrievable Bridge Plugs

³ Drillable Ë Cement Retainers and Bridge Plugs

³ Accessories O

Other Down Hole Tools (Python) Slide 2

EDC, Tomball, TX

1

Why use Squeeze Tools? O

Reasons to use Squeeze Tools ³ Isolate fluids and treating pressure from zone to be treated and rest of well: Ë Ë Ë Ë

BOPs Casing Upper Zones Lower Zones

Slide 3

EDC, Tomball, TX

Types of Squeeze Tools O

Retrievable ³ Rental Tools (“Service Tools”) ³ Run on Tubing or Drill Pipe ³ Multiset Ë Ë Ë Ë

O

Weight Set Packers Tension Set Packers Retrievable Bridge Plugs (RBP’s) RBP / Packer Combos

Drillable ³ Sales Items ³ Run on Tubing or Wireline Ë Cement Retainers and Bridge Plugs Slide 4

EDC, Tomball, TX

2

Packer Components Slips

Packing Elements

Hydraulic Hold Down Button

Drag Blocks

“J” Slot Mechanism

Slide 5

EDC, Tomball, TX

Packer Components (cont.) O

Drag Blocks ³ Friction allows rotation of the outer cage relative to the inner mandrel to manipulate the “J” mechanism

O

“J” Slot Mechanism ³ ³ ³ ³ ³

Various configurations (internal, external) Short side of “J” limits travel of Slips Rotation LH or RH Auto or Manual Long Side of “J” allows slips to ride up over cone ³ Slips grip casing ³ Packer “sets” Slide 6

EDC, Tomball, TX

3

Packer Components (cont.) O

Slips ³ Steel or Carbide (hard casing)

O

Packing Elements ³ Elastomers 70 to 95D

O

Hold Down Buttons ³ Steel or Carbide ³ Hydraulically operated ³ Pressure from BELOW

O

Internal By-pass ³ Decreases “swab” effect Slide 7

EDC, Tomball, TX

Packer Components (cont.)

Slide 8

EDC, Tomball, TX

4

Compression Set Packers O O O O O

TST3 Service Packer TST2 Service Packer SD-1 Squeeze Tool HPHT Service Tool MR 1220 Retrievable Squeeze Tool ³ Used exclusively internationally

O

MR 1223 Retrievable Squeeze Tool ³ Used exclusively internationally

O

MR 220 Retrievable Squeeze Tool ³ Obsolete Slide 9

EDC, Tomball, TX

TST3 Service Packer

Slide 10

EDC, Tomball, TX

5

Tension Set Packer O

TS Squeeze Tool ³ Set in TENSION ³ Use in shallow to medium depths ³ Minimum Slack-off weight for compression set packers ¸ 4 1/2” = 7,000 lbf (114.3 mm = 3,114 daN) ¸ 9 5/8” = 10,000 lbf (244.475 mm = 4,448 daN)

Slide 11

EDC, Tomball, TX

Retrievable Bridge Plugs O

Retrievable Bridge Plugs (RBP) ³ Cup Type (CP) Retrievable Bridge ³ WRP Retrievable Bridge Plug ³ PSTG Retrievable Bridge Plug

O O O

Run on Wireline or Tubing Combination with Squeeze Pkr Additional Components ³ Drag Springs, Fishing Neck Slide 12

EDC, Tomball, TX

6

Retrieving Heads

Slide 13

EDC, Tomball, TX

Drillable Cement Retainers O

Cement Retainers ³ Drillable or “Permanent” ³ Wireline, Mechanical, Hydraulic Set Ë Wireline for accurate placement Ë Hydraulic for deviated holes

³ Stinger opens valve to below tool Ë Pull stinger, close valve

³ Conversion Kits for Bridge Plugs Ë No valve

Slide 14

EDC, Tomball, TX

7

SV-5 Sales Slide O O O O O O O O O

Available in 4-1/2” - 20” (114.3 mm – 508 mm) 10K psi (68,948 kPa) rated through 7-5/8” (200.025 mm) 350 °F (176.7 °C) temperature rating Positive closure of sliding valve when stinger is removed Can be run on wireline or tubing/D.P. Easily converted to bridge plug or mud disposal packer Components rotationally lock for easy drill out 2 3/8” - 4” (60.325 mm - 101.6 mm) tubing retainer Perforating Guns can be ran below Packer Slide 15

EDC, Tomball, TX

Cement Retainers: SV-5 (cont.) SV-5 with Mechanical Setting Tool and Stinger

Slide 16

EDC, Tomball, TX

8

Unloader Valve for Spotting Cement

Slide 17

EDC, Tomball, TX

Ground (or Floor) Squeeze Manifold

Slide 18

EDC, Tomball, TX

9

Python Composite Plug O

Description ³ Substantially non-metallic permanent bridge plug ³ Use in cased holes for zonal isolation or well abandonment ³ Optimized for multiple fracturing operations ³ Designed for fast drill out

Slide 19

EDC, Tomball, TX

Python Composite Plug (cont.) O

Features ³ Substantially non-metallic components. ³ Intrinsic rotational lock among all parts ³ Interlocking design at top and bottom of each plug allows a milled plug to lock into plug below. ³ Slips are rotationally locked to the cone at all times ³ Use of internal voids in slips results in many small pieces while milling, easily circulated out. Slide 20

EDC, Tomball, TX

10

Python Composite Plug (cont.) O

System elements ³ Hydraulic setting tool Ë Allows circulation while running in the hole Ë Allows circulation to the top of the Python plug

³ Solid finned centralizer Ë Keeps the plug off the side of the casing improving performance (reduces the risk of a crooked set)

³ Python Plug Models Ë Model LT 5 1/2” - 200°F, 5,000 psi (139.7 mm, 93.3 °C, 34,474 kPa) Ë Model MT 3 1/2”, 4 1/2”, 5 1/2” - 275°F, 6,000 psi (88.9 mm, 114.3 mm, 139.7 mm, 135 °C, 41,368 kPa) Ë Model HT 3 1/2”, 4 1/2”, 5 1/2” - 350°F, 10,000 psi (88.9 mm, 114.3 mm, 139.7 mm, 176.7 °C, 68,948 kPa)

³ Cement Retainer Design (Under development)

Slide 21

EDC, Tomball, TX

Python Video

Slide 22

EDC, Tomball, TX

11

Tool Facts O

O

O O

Most squeeze tools (packers) are compression-set Most-used BJ tools are TST3, 1220 MR and SD-1 For shallow work, use TS Packer For accuracy, set retainer on electric wireline

Slide 23

EDC, Tomball, TX

Tool References

Slide 24

EDC, Tomball, TX

12

BJ T.S.T.² Retrievable Packer Product Information

Applications The BJ T.S.T.2 Retrievable Packer is used for testing, acidizing, formation fracturing and squeeze cementing. It's a full-opening compression-type packer with an internal pressure actuated hold-down button and a built-in by-pass with a face type unloader seal.

Features and Benefits Simple Operation Set with either right or left hand rotation—predetermined before entering the hole. Three-quarter turn rotation to set tool. Tool can be set as many times as desired without having to rotate again. Three-quarter turn rotation to unjay tool and move down hole if necessary. Full Bore Opening Full bore permits through-tubing perforating. Greater Safety The specially designed by-pass system permits all of the well fluids to travel completely around the bottom of the tool while either circulating or reversing. Releases Easily Face type unloader open when tubing is picked up. Pressure is equalized across the hold down button via internal by-pass even if tubing is plugged with cement or other solids. Built-In Collet Eases Circulation Hold by-pass open while circulating or reversing. Designed for deviated holes. When setting tool, collet allows by-pass to stay open, thus allowing hold down buttons to stay in place until packing rubbers are packed off. Availability 4½" - 16"

BJ SERVICES COMPANY

BJ T.S.T.² Retrievable Packer Product Information

Technical Data Specification Guide Casing OD (in)

Casing Weight (lbs/ft)

Guide Gauge Ring O.D. (in)

Minimum Packer I.D. (in)

4½ 4¾

Absolute Slip Range Min. (in) Max. (in)

Absolute Button Range Min. (in) Max. (in)

9.5-13.5

3.76

1.625

3.810

4.312

3.810

16

3.76

1.625

3.810

4.312

3.810

4.090

5

15-18

4.125

1.625

4.125

4.687

4.126

4.409 4.561

4.090

5

11.5

4.250

1.625

4.50

4.956

4.274

5½

26

4.250

1.625

4.50

4.956

4.274

4.561

5½

20-23

4.50

1.875

4.625

5.166

4.484

4.950

5½

15.5-20

4.64

1.875

4.625

5.166

4.484

4.950

5½

13-15.5

4.781

1.875

4.625

5.166

4.764

5.190

5¾

22.5

4.781

1.875

4.625

5.166

4.764

5.190

6

26

5.781

1.875

4.625

5.166

4.764

5.190

6

20-23

5.062

1.875

5.000

5.541

5.000

5.390

7

57.1

5.062

1.875

5.000

5.541

5.000

5.390

6

15-18

5.156

1.875

5.000

5.541

5.136

5.560

7

49.5

5.406

1.875

5.375

5.916

5.386

5.791

6 5/8

34

5.406

1.875

5.375

5.916

5.386

5.791

6 5/8

28-32

5.484

1.875

5.375

5.916

5.386

5.791

7

44-46.4

5.484

1.875

5.375

5.916

5.386

5.791

7

38-41

5.656

1.875

5.675

6.216

5.632

5.941

6 5/8

24

5.656

1.875

5.675

6.216

5.632

5.941

7

38

5.70

2.375

5.750

6.621

5.597

6.135

7

32-35

5.85

2.375

5.750

6.621

5.597

6.135

7

26.29

5.95

2.375

5.750

6.621

5.861

6.538

7

20-26

6.078

2.375

5.750

6.621

5.861

6.538

7

17-20

6.266

2.375

6.375

7.241

6.297

7.132

7 5/8

45.30

6.266

2.375

6.375

7.241

6.297

7.132

7 5/8

33.7-39

6.450

2.375

6.375

7.241

6.297

7.132

7 5/8

24-29.7

6.670

2.375

6.375

7.241

6.297

7.132

7 5/8

20-24

6.812

2.375

6.375

7.241

6.297

7.132

8 5/8

44-49

7.312

2.375

7.437

8.304

7.313

8.750

8 5/8

20-28

7.781

2.375

7.906

8.772

7.313

8.750

9 5/8

47-53.5

8.218

3.00

8.250

9.313

8.117

9.063

9¾

59.20

8.218

3.00

8.250

9.313

8.117

9.063

9 7/8

62.8

8.218

3.00

8.250

9.313

8.117

9.063

9 5/8

40-47

8.438

3.00

8.250

9.313

8.117

9.063

9 5/8

29.3-36

8.593

3.00

8.343

9.407

8.117

9.063

10¾

65.7-81

9.125

3.00

9.250

10.313

9.125

9.903

10¾

55-60

9.375

3.00

9.250

10.313

9.125

9.903

10¾

32.75-51

9.625

3.00

9.250

10.313

9.125

9.903

11¾

38-71

10.375

3.00

10.375

11.438

10.375

11.313

13 3/8

77-102

11.625

3.00

11.750

12.813

11.750

12.800

13 3/8

48-72

12.125

3.00

11.750

12.813

11.750

12.800

13½

81.40

11.625

3.00

11.750

12.813

11.750

12.800

13 5/8

88.20

11.625

3.00

11.750

12.813

11.750

12.800

16

84-109

14.375

3.25

14.500

15.563

14.500

15.563

16

65-84

14.698

3.25

14.500

15.563

14.500

15.563

The above features and/or data are supplied solely for informational purposes and BJ Services Company makes no guarantees or warranties, either expressed or implied, with respect to their accuracy or use. All product warranties and guarantees shall be governed by the BJ Services Company standard at the time of sale or delivery of service. Actual product performance or availability depends on the timing and location of the job, the type of job and the particular characteristics of each job. This document is controlled by the reference date. To ensure that this is the current version, please reference the Services section of the BJ Services Website (www.bjservices.com) or ask your BJ representative.

11/6/02

BJ SERVICES COMPANY

BJ T.S.T.³ Service Packer Product Information

Applications The BJ T.S.T.3 Service Packer is used for testing, acidizing, formation fracturing and squeeze cementing. It's a full-opening compression-type packer with internal pressure actuated hold-down buttons and a built-in by-pass with a face type unloader seal.

Features and Benefits Simple Operation Set with either right or left hand rotation—predetermined before entering the hole. Three-quarter turn rotation to set tool. Tool can be set as many times as desired without having to rotate again. Three-quarter turn rotation to rejay tool and move down hole if necessary. Full Bore Opening Full bore permits through-tubing perforating. Greater Safety The specially designed by-pass system permits all of the well fluids to travel completely around the bottom of the tool while either circulating or reversing. Releases Easily Face type unloader open when tubing is picked up. Pressure is equalized across the hold down button via internal by-pass even if tubing is plugged with cement or other solids. Keyed Connections Keyed top and bottom subs insure reliable torque transmission through tool. Built-In Collet Eases Circulation Hold by-pass open while circulating or reversing. Designed for deviated holes. When setting tool, collet allows by-pass to stay open, thus allowing hold down buttons to stay in place until packing rubbers are packed off. Dovetail Slip System Insures Positive Retraction of the slips when releasing/retrieving the packer. Carbide Insert Slips and Buttons Insures a positive reliable grip in old, corroded, or scaled casing surfaces. Reliable Packer Control The external J Slot packer control reduces the possibility of debris accumulation which can compromise packer setting and releasing. Availability 4½" - 20" The above features and/or data are supplied solely for informational purposes and BJ Services Company makes no guarantees or warranties, either expressed or implied, with respect to their accuracy or use. All product warranties and guarantees shall be governed by the BJ Services Company standard at the time of sale or delivery of service. Actual product performance or availability depends on the timing and location of the job, the type of job and the particular characteristics of each job. This document is controlled by the reference date. To ensure that this is the current version, please reference the Services section of the BJ Services Website (www.bjservices.com) or ask your BJ representative.

1/7/03

BJ SERVICES COMPANY

HPHT Service Packer Product Information

Applications The HPHT Service Packer is a retrievable high performance tool designed for use in high pressure high temperature wells. The familiar compression-set packer design allows this packer to be operated with standard techniques and accessory tools in a variety of applications including temporary abandonment with Hurricane valves, squeeze cementing, formation fracturing, acidizing, and casing testing. It is designed for reliable, multi-set, casing-friendly operation at temperatures up to 430º F and 12,000 psi differential pressure. Premium high temperature polymeric components are standard on this packer, and optional elastomers are available for aggressive chemical environments. Check with BJ’s Downhole Tool Engineering Department for advice on elastomer options.

Features and Benefits •

Robust design for high temperature high pressure well applications.

•

Familiar compression-set configuration for ease of operation.

•

Keyed mandrel connections for insurance against back-off downhole.

•

All o-rings on this packer can be tested prior to leaving the BJ Service Center.

•

Simple, rugged right-hand J-slot packer control for downhole reliability. Left-hand and straight J-slot options available on special order (allow adequate lead time for delivery).

•

Casing-friendly slip and button design allows use at up to 12,000 psi differential pressure without permanently deforming casing. †

•

Developed for use in casing grades P-110 and Q-125; also suitable for use in L/N-80 and C-95 grades. †

•

Standard nitrile and viton® elastomer trim. Aflas® elastomer option for aggressive chemical environments available on special order (allow adequate lead time for delivery).

•

Operation to 5,000 psi differential pressure @ 350ºF (176°C) and multi-set capability with the standard nitrile packing element package.

•

Operation to 12,000 psi differential pressure @ 430ºF (221°C) and multi-set capability with the optional high temperature viton® packing element package.

†

Casing grade and weight is important in achieving this performance check the specification guide for further information.

BJ SERVICES COMPANY

HPHT Service Packer Product Information

Technical Data Specification Guide O.D. (in.)

Casing Weight T & C (lbs./ft.)

Tool Assembly Number

Gage Ring O.D. (in.)

Minimum Mandrel ID (in.)

Setting Range, Casing ID ( in.) Threads, Box Up, Minimum Maximum Pin Down ID F/Setting ID F/Setting (in.)

7

35.0

72676-1

5.763

2.37

5.920

6.004

3½IF

7

38.0

72676-1

5.763

2.37

5.920

6.004

3½IF

9 5/8

53.5

65722-1

8.35

3.00

8.535

8.625

4½IF

9 5/8

62.8

65722-1

8.35

3.00

8.535

8.625

4½IF

Companion Equipment Description (in.)

Part Number

Comments

3½ HPHT Unloader Valve

71431-1

12,000 psi at 430°F

4½ HPHT Unloader Valve

70514-1

11,000 psi at 400ºF

4¾ Hurricane Valve

T434192

275°F

6 1/8 Hurricane Valve

434073-1

275°F

Pressure and Temperature Limitations Packer Size (in.)

Operating Temperature Gauge

Maximum Operating Pressure

7 Std.

200°F - 350°F

10,000 psi at 350°F

7 Hi-Temp

250°F - 430°F

12,000 psi at 430°F

9 5/8 Std.

200°F - 350°F

10,000 psi at 350ºF

9 5/8 Hi-Temp

250°F - 400°F

11,000 psi at 400°F


10/17/02

BJ SERVICES COMPANY

BJ Services Company, USA Service Tools Technical Manual Subject: 9 5/8” High Pressure High Temperature Service Packer Index No: 2009

Revision:

Date: 7/15/98

Confidential Proprietary Information BJ Services Company, USA

Page 13 of 16

!"

# !

$"#$

' % '

%&%

TS Squeeze Tool Product Information

Applications Full opening, retrievable, tension-set squeeze packer. Designed for squeeze cementing, testing or treating activities on shallow-to-medium depth wells.

Features and Benefits Full Opening Through-tubing wireline operations are made possible by the full opening mandrel. Tubing Protection In the event of pressure reversal, excessive tubing stretch is avoided by the opposed slip design. Instant Pack-off Pack-off is achieved by raising the tubing and applying tension to the tool. Pressure differentials are then held from both above and below the tool. Reliable Release The operator has the option to rotate the tool out of the hole even under the most adverse downhole conditions. Unloader Sub The full opening Unloader Sub is run with the TS to allow equalization of pressure around the tool.

BJ SERVICES COMPANY

TS Squeeze Tool Product Information

Technical Data Dimensional Data Casing

OD (in)

Weight #/ft

Min. (in.)

Max. (in.)

Gage & Guide Ring OD (in)

4 1/2

9.5-13.5

3.880

4.090

3.771

21

4.029

4.154

3.938

18

4.151

4.276

4.062

Range

5

15

4.283

4.408

4.125

11.5-13

4.369

4.560

4.250

Packer Absolute Slip Range Max. Min. (in.) (in.)

Min. ID

3.850

4.220

1.950

4.150

4.410

4.280

4.545

4.778

4.500

4.610

4.950

4.767

4.950

4.641

4.610

4.950

13-15

4.849

5.044

4.781

4.950

5.190

5 3/4

19.5-22.5

4.865

5.090

6 5/8

24-26

5.830

5.921

5.656

5.830

6.184

7

38-40 5.812

5.830

6.184

5.968

6.090

6.540

20-22

5.864

6.049

7

32-35

5.879

6.094

6 5/8

7

7 5/8

17

6.090

6.135

28-30

6.090

6.214

23-26

6.151

6.366

6.080 6.280

2 3 /8

4.560

20-23

6 5/8

2 3 /8 EU 8Rd X

15.5-17

5 1/2

(in.)

Standard Threads (Box Up x Box Down

EU 8Rd

2.375

EU 8Rd X 2 7/8

20

6.331

6.456

17

6.413

6.538

33.7-39

6.500

6.765

6.453

26.4-29.7

6.770

6.969

6.670

20-24

6.900

7.125

6.810

EU 8Rd 6.530

6.875

6.770

7.130


1/7/03

BJ SERVICES COMPANY

Cup Type Retrievable Bridge Plug Product Information

Applications The Cup Type (CT) Retrievable Bridge Plug is used for zone isolation while testing, treating or other service that is being performed on a well. The CT holds pressure from above or below and is compatible with the BJ retrievable squeeze tools.

Features and Benefits Self-Energized Pack-Off Differential pressure from either above or below the tool is utilized to achieve pack-off. Opposing Slips The plug is kept in place even under extreme changes in differential pressures. Simple Release The straight-pull release allows easy retrieval and flexibility for special well treatment applications.

Technical Data Specification Guide Tool Size

Casing

Range

(in)

(in)

(lbs/ft)

(in)

4½

4½

9.5-13.5

3.771

4½

4½

21

3.937

5

5

18

4.062

5

5

15

4.125

5½

5½

20-23

4.500

5½

5½

15.5-17

4.641

5½

5½

13-14

4.781

7

7

32-38

5.656

7

7

29

5.968

7

7

23-26

6.078

7

7

17

6.266

7 5/8

7 5/8

33.7-39

6.453

5/8

7 5/8

26.4-29.7

6.672

9 5/8

9 5/8

CALL FOR AVAILABILITY

10 ¾

10 ¾


13 3/8

13 3 /8


7

Gauge Ring


1/7/03

BJ SERVICES COMPANY

WRP Retrievable Bridge Plugs Product Information

Features and Benefits The WRP Retrievable Bridge Plug is a high-pressure bridge plug which offers the advantages of electric wireline setting The WRP Retrievable Bridge Plug can be used for isolating zones, well stimulation or wellhead repair since the plug can be lubricated in and out of the hole under pressure, thus eliminating the need for killing the well.

Features and Benefits • Short and compact. • Holds pressure from above and below. • Rugged construction. • Heavy duty bi-directional slips. • Circulate to within 2-in. without latching the retrieving tool. • Equalizing ports not affected by differential pressure. • Retrievable on tubing or sandline. • Optional ball catcher available. Casing OD

Weight

Casing ID Range (in.)

(in.)

(lbs./ft.)

Min.

Max.

4 1/ 2

9.5-13.5

3.920

4.090

5

15.0-18.0

4.276

4.408

5 1/ 2

20.0-23.0

4.670

4.778

5 1/ 2

15.5-20.0

4.778

4.950

5 1/ 2

13.0-15.5

4.950

5.044

6 5/ 8

28.0-32.0

5.675

5.701

6 5/ 8

20.0-24.0

5.921

6.049

7

32.0-35.0

6.004

6.094

7

26.0-29.0

6.184

6.276

7

23.0-26.0

6.276

6.366

7

17.0-20.0

6.538

6.456

7 5/ 8

39.0-45.3

6.538

6.625

7 5/ 8

33.7-39.0

6.625

6.765

7 5/ 8

24.0-29.7

6.875

7.025

7 5/ 8

20.0-24.0

7.025

7.125

9 5/ 8

47.0-53.5

8.535

8.681

9 5/ 8

40.0-47.0

8.681

8.835

9 5/ 8

29.3-36.0

8.921

9.063


10/17/02

BJ SERVICES COMPANY

M/S Bridge Plugs Product Information

Applications The M/S Bridge Plugs are premium bridge plugs designed for high temperature and pressure. It is used for temporary or permanent abandonment.

Features and Benefits • Cost competitive. • Constructed with drillable material. • Retaining rings to assist in preventing element extrusion. • 10,000 psi rated at 300°F (149°C) (70 Durometer nitrile element) • 10,000 psi rated at 350°F (177°C) (80 Durometer nitrile element) • 10,000 psi rated at 400°F (204°C) (90 Durometer nitrile element) • Sets either mechanically or wireline. • Can be converted to cement retainer. • Sets in all premium grades of casing. • Every CIBP is internally pressure tested to insure material integrity and workmanship. • All shear stud material is tensile tested to insure proper shear value. • All 4 ½”and 5 ½” CIBP mandrels are tensile tested to 35,000 lbs. SHEAR STUD

SHEAR SCREW


10/17/02

BJ SERVICES COMPANY

Mechanical Setting Tool Product Information

Applications The Mechanical Setting Tool is designed to run and mechanically set a Cement Retainer or Bridge Plug at any depth on tubing or drill pipe. The Mechanical Setting Tool is used anytime it is advantageous to run a Cement Retainer or Bridge Plug on tubing or drill pipe. Cement Retainers can be set and pressure tested in a single trip.

Features • Bow Springs - Provide positive control and allows one size Mechanical Setting Tool to cover a large range of casing weights.

• Locked together safety - The Mechanical Setting Tool and Cement Retainer or Bridge Plug tools are shear pinned together for safer running.

• Protected slips - The upper slips are held in a safe retracted position while running in.

• Versatile - Allows user to set, pressure test tubing, and squeeze in a single trip.

• Simple design - Can quickly be configured to set Cement Retainers or Bridge Plugs.

Technical Data Casing OD

Weight

(in.)

(lbs/ft)

Tool Preferred Range of Casing ID's (in.) Min.

Max. O.D. (in.)

Max.

4-1/2

9.5-15.1

3.826

4.090

5

11.5-20.8

4.156

4.560

5-1/2

13-23

4.580

5.044

4.312

5-3/4

14-25.2

4.890

5.290

4.700

6-5/8

17-32

5.595

6.135

7

17-35

6.004

6.538

7-5/8

20-39

6.625

7.125

8-5/8

24-49

7.511

8.097

7.125

9-5/8

29.3-58.4

8.435

9.063

8.125

10-3/4

32.75-60.7

9.660

10.192

9.438

11-3/4

38-60

10.772

11.150

10.437

10.192

15.250

3.593

5.375 6.312

11-3/4

60-83

13-3/8

48-80.7

12.175

12.715

11.880

9.937

16

65-109

14.688

15.250

14.125

20

94-133

18.730

19.124

18.375


11/1/02

BJ SERVICES COMPANY

W/L Bridge Plugs Product Information

Applications The W/L Bridge Plugs are premium bridge plugs designed to run on electric line. They are used to isolate zones for temporary or permanent abandonment.

Features and Benefits • Cost competitive. • Constructed with drillable materials. • Retaining rings to assist in preventing element extrusion. • Top set with shear stud. • No tension mandrel required. • Standard packing element rated at 300°F (148°C). • Higher temperature packing element available upon request. • Runs on existing electric line setting tool with most existing sleeves. • Sets in all premium grades of casing.

BJ SERVICES COMPANY

W/L Bridge Plugs Product Information

Technical Data Specification Guide Setting Range (in)

Casing O.D. (in)

T&C Weight (lbs)

Plug O.D. (in)

Min.

Max.

2 3 /8

4.0-5.8

1.750

1.780

2.074

2 7 /8

6.4-6.5

2.220

2.340

2.525

3 1/2

5.75-10.3

2.750

2.867

3.258

4

5.6-14.0

3.140

3.340

3.732

4 1/2

9.5-16.6

3.562

3.826

4.090

5

11.5-20.8

3.937

4.154

4.560

5 1/2

13.0-23.0

4.312

4.580

5.044

5 3/4

14.0-25.2

4.699

4.890

5.290

6 5/8

17.0-32.0

5.375

5.595

6.135

7

17.0-35.0

5.687

6.000

6.538

7 5/8

20.0-39.0

6.312

6.625

7.125

8 5/8

24.0-49.0

7.125

7.310

8.097

9 5/8

29.3-58.4

8.125

8.379

9.063

10 3/4

32.7-60.7

9.437

9.660

10.192

11 3/4

38-60

10.437

10.772

11.150

11 3/4

60-83

9.937

10.192

10.772

13 3/8

48-84.5

11.880

12.175

12.175

16”

65-118

14.125

20”

94-133

18.375

15.250 18.730

19.124


10/17/02

BJ SERVICES COMPANY

BJ Model SV-5 Cement Retainer Product Information

Applications A drillable squeeze packer, the BJ Model SV-5 Cement Retainer is used primarily in squeeze cementing. With slight modification it can also be used as a mud disposal packer or as a permanent bridge plug. Setting can be accomplished by any of three methods – wireline, hydraulic, mechanical – for maximum adaptability to a variety of conditions.

Features and Benefits • Cast, case-hardened slips – Designed to allow for faster drill-up, this quality of hardness means the SV-5 can work in all premium-grade casings. Case hardening provides high-quality, consistent hardness in the wickers. • Piston-ring type back-up rings – Durable design eliminates the hazard of premature expanding of rings as a result of fluid passage or rough handling. • Sleeve-valve design – Positive control of the valve is achieved simply by picking up or setting down. The balanced design allows easy movement, even under high pressure differentials. • Small ODs – Designed with smaller outside diameters for faster running in heavy, viscous fluids. • Drillability – The tool remains in a locked position for ease of drill-up. Materials specifications provide additional drillability by requiring quality control of cast materials to eliminate high-carbon within specified grades. • Hydraulic setting for directional holes – Hydraulic setting with no rotation required eliminates premature setting and makes the tool ideal for use in directional holes, no matter how deviated. Simple, reliable setting has made the SV-5 a proven performer in any depth, in any hole. • Modular design – Allows simple field conversion to a Bridge Plug or Flapper Valve Cement Retainer. • Custom design availability – For special applications beyond stated specifications or design, tools for extended service ranges can be customdesigned for your specific needs.

BJ SERVICES COMPANY

BJ Model SV-5 Cement Retainer Product Information

Technical Data Specification Guide Recommended Casing IDs for Setting

Casing OD

Weight T&C

Tool OD

(In.)

(In.)

(In.)

(In.)

(In.)

4 1/ 2

9.5 - 15.1

3.593

3.826

4.090

5

11.5 - 18

3.937

4.154

4.560

5 1/ 2

13 - 23

4.312

4.580

5.044

6 5/ 8

17 - 32

5.375

5.595

6.135

7

32 - 44

7

17 - 38

5.688

5.795

6.538

6.312

6.625

7.263

7.125

7.310

8.097

8.125

8.379

9.063

Min.

Max.

45.3 7 5/ 8

20 - 39

7 3/ 4

46.1

8 5/ 8

24 - 49

8 3/ 4

49.7

9 5/ 8

29.3 - 53.5

9 3/ 4

59.2

9 7/ 8

62.8

103/4

60.7 - 81.0

9.000

9.250

9.660

103/4

32.7 - 60.7

9.437

9.660

10.192

133/8

72 - 102

131/2

81.4

11.375

11.633

12.347

133/8

88.2

133/8

48 - 84.5

131/2

81.4

11.88

12.175

12.715

135/8

88.2

16

65-133

14.125

14.688

15.250

20

94-133

18.375

18.730

19.124

Working Specifications Size (Inches) Temp.

4 1 / 2" thru

8 5/ 8" thru

103/4" thru

7 5 / 8"

9 5/ 8"

133/8"

375°F

350°F

350°F

190°C

177°C

177°C

Service

Standard*

Standard*

Standard*

Working Pressure (psi) Below

10,000

8,000

6,000

Above (psi)

10,000

6,000

5,000

*Standard service is all oil and gas well fluids excluding hydrogen sulfide (H2S) and carbon dioxide (CO2). The above features and/or data are supplied solely for informational purposes and BJ Services Company makes no guarantees or warranties, either expressed or implied, with respect to their accuracy or use. All product warranties and guarantees shall be governed by the BJ Services Company standard at the time of sale or delivery of service. Actual product performance or availability depends on the timing and location of the job, the type of job and the particular characteristics of each job. This document is controlled by the reference date. To ensure that this is the current version, please reference the Services section of the BJ Services Website (www.bjservices.com) or ask your BJ representative.

10/17/02

BJ SERVICES COMPANY

Stinger Seal Assembly Product Information

Applications The Stinger Seal Assembly is used for sealing into, cementing thru and closing the slide valve on a Wireline Set Cement Retainer. The Stinger Seal Assembly will open the slide valve and latch into the Cement Retainer when approximately 3,000 to 5,000 pounds of set down weight is landed on the Cement Retainer. Two inches of upward workstring movement at the cement retainer will close the slide valve for fluid containment above or below the Cement Retainer and will allow tubing testing. Two inches of downward movement at the Cement Retainer will open the slide valve and allow fluid to be pumped through the Cement Retainer. Approximately 5,000 to 10,000 pounds tension at the Cement Retainer is required to snap-out. Each time the seal assembly is snapped out, the snap-out force is reduced. The snap-out force will stabilize at about 5,000 pounds. Snap in force will stabilize at about 2,500 pounds. The Stinger Seal Assembly can also be released from the Cement Retainer by pulling 1,000 pound tension over string weight at the tool and rotating 8 to 10 turns to the right. Forces created by pressures applied to the work string and annulus act upon the Stinger Seal Assembly and work string during cementing operations. Under certain conditions these forces can cause the Stinger Seal Assembly to pump out of the Cement Retainer.


11/1/02

BJ SERVICES COMPANY

BJ PythonTM MT Composite Bridge Plug* Product Information

Description The BJ Python MT Composite Bridge Plug is constructed of high-tech composite materials, which are easily millable with a coiled tubing unit.

Features and Benefits Rapid Mill Out Two tapered mating surfaces at the top and bottom of each plug rotationally lock plug remnants, promoting ultra-fast mill out. Temperature Rating The tool is designed to operate at 275°F (135°C) with 10,000 psi differential pressure. Slip Design The slip design combines good bite into the casing with easy millability. Standard Deployment The tool is run on the Baker E-4 or E-5 Wireline Pressure Setting Assembly.

Technical Data Specification Guide

**

**

Casing OD (in.) Tool Size

Casing Weight Range (lbs/ft)

Baker WLPSA

3½

9.2

#05 E-5

4½

9.5 - 15.1

#10 E-4

5½

14.0 - 20.0

#20 E-4

*Patent Pending **Contact Service Tools Engineering for availability

Consult your local BJ Services Tool office for additional information. The above features and/or data are supplied solely for informational purposes and BJ Services Company makes no guarantees or warranties, either expressed or implied, with respect to their accuracy or use. All product warranties and guarantees shall be governed by the BJ Services Company standard at the time of sale or delivery of service. Actual product performance or availability depends on the timing and location of the job, the type of job and the particular characteristics of each job. This document is controlled by the reference date. To ensure that this is the current version, please reference the Services section of the BJ Services Website (www.bjservices.com) or ask your BJ representative.

6/18/03

BJ SERVICES COMPANY

10,000 PSI Squeeze Manifold Product Information

Applications Monitors and controls fluid pressure and movement during critical squeeze cementing operations. BJ’s 10,000 PSI Squeeze Manifold is the most reliable squeeze manifold system available in the industry.

Features and Benefits Positive Fluid Control The six-valve design provides positive fluid control under the most demanding conditions. Pressure Rating Manifolds are individually tested to 15,000 psi (103,421 kPa) and rated at 10,000 psi (68,948 kPa) working pressure. Pressure Monitoring Each manifold is available with a special gauge box for accurate monitoring of fluid pressures. Knock-Down Design Transport and set-up anywhere is an easy procedure due to all integral connections.

Technical Data Specification Guide Test Pressure

15,000 psi

Working Pressure

10,000 psi


1/7/03

BJ SERVICES COMPANY

Cementing Operations Section 15

Printed: 6/10/2006

EDC, Tomball, TX

Cementing Operations O

Cementing Equipment ³ Mixing Systems ³ Offshore Cementing Equipment ³ Land Cementing Equipment ³ Instrumentation

O

Cementing Operations Standard Practices

Slide 2

EDC, Tomball, TX

1

Mixing Systems

Printed: 6/10/2006

EDC, Tomball, TX

Mixing Module

Slide 4

EDC, Tomball, TX

2

Mixing Module

O O O

Knife gate Cylinder Mix Bowl

Slide 5

EDC, Tomball, TX

RAM Mixing System

Slide 6

EDC, Tomball, TX

3

ACC-II System Job Program Density Yield Water/sack Slurry #1 12.7 1.8 8.5 Slurry #2 15.7 1.17 5.19

Slide 7

EDC, Tomball, TX

ACC-II Basic Operation O O

ACC stands for Automated Cement Control The ACC II monitors ³ ³ ³ ³

O

Downhole Rate Water Rate (And Water Valve Position) Slurry Density (And Knife Gate Position) Surge Can Weight

The ACC-II Controls ³ Water Rate (And Water Valve Position) ³ Cement Rate (And Knife Gate Position) Ë Which Ultimately Controls Slurry Density

³ Bulk Valve Position Ë Which Ultimately Controls Surge Can Level Slide 8

EDC, Tomball, TX

4

ACC-II System ACC-II Module

Bulk Valve

Surge Can

Bulk Supply

Load Cell Downhole Rate

Knife Gate Valve Mix Water Pump

Flow Meter

Pri Tub Mixing Densimeter

CONTINUOUS MIX MODE

Downhole Densimeter Sec Tub

Recirculating Pump

Downhol e Pump

Slide 9

EDC, Tomball, TX

Pacemaker Pump

Plunger Max WP dia. psi 3.5” 15,000 4.0” 12,500 4.5” 10,000 5.0” 8,500 5.5” 7,000 6.0” 6,000 Stroke = 4” Slide 10

EDC, Tomball, TX

5

Pacemaker Pump Pump Cover

Connecting & Crosshead Assembly

Crank Shaft

Counter Shaft Oil Pan Slide 11

EDC, Tomball, TX

Pacemaker Pump Discharge Valve Cap

Discharge Valve

Ram Wash

Discharge Manifold

Oilers

Plunger

Plunger Rod

Suction Manifold Slide 12

EDC, Tomball, TX

6

Offshore Cementing Equipment

Printed: 6/10/2006

EDC, Tomball, TX

348 RAM Skid

Slide 14

EDC, Tomball, TX

7

348 RAM Skid

348 RAM with sound enclosure and chemical additive platform

Slide 15

EDC, Tomball, TX

35-8-5 PSM Skid

8 bbl mixing tub

Slide 16

EDC, Tomball, TX

8

35-8-5 RAM Skid

24 bbl mixing tub and liquid additive storage tanks

Slide 17

EDC, Tomball, TX

40-75-2 RAM Electric Skid

Slide 18

EDC, Tomball, TX

9

Seahawk Skid Design

Slide 19

EDC, Tomball, TX

Seahawk Features & Benefits O O O O O O

Due September 2005 True 100% backup Advanced density control - ACC-II Dual recirculating mixer with de-Aerator Smaller, Lighter, More powerful, More versatile Variable Main Drivers (Electric AC, DC, up to 1300 hhp) ³ Engines EPA tier-II compliant plus history files )

O O

Improved pressure testing capabilities & low rate pumping No external auxiliary hydraulic power pack ³ Reduced risk of oil spills from complex hydraulic systems

O O O

Quick transitions between slurry designs Integral overpressure shutdown system Increased standard surge tank capacity by 25 to 50% Slide 20

EDC, Tomball, TX

10

Offshore Unit Specifications 35-8-5/PSM

35-8-5/RAM

SCP-348/RAM

Seahawk

Brake Horsepower

670

780

980

1,000

Hydraulic Horsepower

510

510

832

850

Weight, lbs

32,500

38,900

53,200

47,000

Length, in.

234

273

313

287

Height, in. (Surge Tank)

136

159

154

154

Surge Tank Capacity, ft3

46

33

40

50 Integral Electric-Hydraulic Power Pack

Auxiliary Hydraulic Power

None

External Diesel Power Pack

Integral Hydraulics From Deck Engines

Backup Mixing System

None

None

Yes (common reservoir)

Yes

Mixing Tub Capacity, bbl

3& 8

25

21

8

None

Tub Retention / Volume

Tub Retention / Volume

Deaerator

Deaeration Method

Slide 21

EDC, Tomball, TX

Land Cementing Equipment

Printed: 6/10/2006

EDC, Tomball, TX

11

HAWK Twin Cementer

O O O

Road Engine Cummins ISM 435 hp Deck Engine Cummins QSM 446 hp Micromotion Densimeter Flowmeter

O O O

BJ Pacemaker Pumps Deaireator Mixing Tank Full ACC Operation Slide 23

EDC, Tomball, TX

HAWK Twin Cementer

Slide 24

EDC, Tomball, TX

12

148 LAM / PSM

O O O

DD 8V92 @492 bhp Allison 750 BJ Pacemaker Pumps

O

DB-IV Densimeter Direct Feed or Surge Can

O

7 bbl Recirculator

O

Slide 25

EDC, Tomball, TX

FALCON Cement Unit

O O O

(2) Detroit Series 60 660 BHP Engines Allison CLT-6061 Electric Shift Transmission (2) Pacemaker Triplex Pumps

Slide 26

EDC, Tomball, TX

13

FALCON Cement Unit O O O

1000 HHP Deaerator Mixing Tank Full ACC Operation

Slide 27

EDC, Tomball, TX

Operator’s Consoles O

Falcon and Hawk Units ³ MCM 2000 Controller ³ UEC -II Engine Controls ³ 3305 Events / Recording ³ 3 Chemical Additives

Slide 28

EDC, Tomball, TX

14

TM 50 bbl Bulk Batch Unit O O O

O

O

O

50 bbl Batch Mix Tank 320 cuft. Bulk Tank Rear chemical pallet area Compressor 160 cfm @ 28 psi 5x6 Mission Slurry Pump 9 bbl wash-up water tank Slide 29

EDC, Tomball, TX

TM 100 bbl Batch Unit O

O

O

100 bbl Batch Mix Tank Rear chemical pallet area (2) 5x6 Mission Slurry Pump

Slide 30

EDC, Tomball, TX

15

TM 600 ST Bulk Unit O O

O

600 cuft Bulk Dense Phase Conveying 40 cfm @ 25 psi

Slide 31

EDC, Tomball, TX

Instrumentation

Printed: 6/10/2006

EDC, Tomball, TX

16

3305 Mini-Monitor O

6 Channel Recorder ³ 2 Rate ³ 2 Pressure ³ 2 Density

O O

O

Strip Chart Recorder Output to JobMaster remote PC Data Cassette for download to computer

Slide 33

EDC, Tomball, TX

Visiplex O

O

O

O

Substitute for the 3305 10.5” LCD, direct sunlight viewable Has digital chart recorder Uses USB memory device instead of Data Cassette

Slide 34

EDC, Tomball, TX

17

Massflow Densimeter

O

O O O

True downhole slurry and displacement rate and volumes Non nuclear slurry density Used both in batch-up and downhole mixing Manufactured by MicroMotion Slide 35

EDC, Tomball, TX

Isoplex Monitoring System O

O

O

Specialized operations like foam or ultra light weight cement monitoring. Supplied in monitoring van or skid Runs JobMaster software

Slide 36

EDC, Tomball, TX

18

JobMaster

O

32 Bit Windows Compatible Data Monitoring, Display, and Storage Program Slide 37

EDC, Tomball, TX

Wireless LAN O O

O

O

O

Eliminates Cables No Modifications to Existing Equipment Used Between 3305, Brain Box and Cementer’s PC in pickup truck on rig Operates on 2.4 Ghz Spread Spectrum Certified License Free Slide 38

EDC, Tomball, TX

19

Cementing Operations Standard Practices

Printed: 6/10/2006

EDC, Tomball, TX

Cementing Operations Standard Practices Reference: BJ Standard Practices O

Slide 40

EDC, Tomball, TX

20

BJ Services - Cementing Manual

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