BP & Chevron - Cement Manual

The ChevronTexaco and BP Cement Manual

Cement Manual

Table of Contents Section 1: Overview: Special Considerations: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Cementing High Pressure - High Temperature wells (HPHT) . . . . . . . . . . . . . . . . . . . . . 1 Cementing in Deep Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Cementing Highly Deviated and Horizontal Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Cementing Extended Reach Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Cementing of Multilateral Junctions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Coiled Tubing Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Estimated job time (including cleanout time for excess cement) . . . . . . . . . . . . . . . . . . 20

Major Factors Influencing Success: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Mud Displacement Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Mud Condition and Mud Conditioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Cement Slurry Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Use of API schedules for measuring slurry Thickening Time(TT) . . . . . . . . . . . . . . . . . . 31 Cementing Equipment Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Access and Application of Best Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Knowledge of Pore Pressure and Fracture Pressure Data . . . . . . . . . . . . . . . . . . . . . . . 35 Knowledge of the Well temperatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Knowledge of Policies and Regulatory Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . 39 The Importance of Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Common Cementing Problems: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Failing to Bump the Top Plug . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Lack of Zone Isolation - Cross Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Annular Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Low Leak-Off Test (LOT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Top-of-Cement Lower than Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Soft Kick Off Plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Liner Tops that Fail Pressure Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Less Common Cementing Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Table of Contents

i “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Roles and Responsibilities: Aim: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65 The Well design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65 Planning a cementing program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Information Needed by the Service Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 The Cementing Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 The interaction with the Other Service Providers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .70

Cement Job Evaluation: Temperature Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73 Acoustic Logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Segmented Ultrasonic Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .79

Section 2: Equipment: Surface and Subsurface Equipment: Surface Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Cement Mixing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Recording . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 High Pressure Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Safety Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Bulk Cement Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13 Cement Heads, Water Bushings, Sweges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15 Float Shoes and Collars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18 Stage Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20

Casing Centralization: Centralization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25 Reduce the Risk of Sticking the Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Non Centralization Equals Poor Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 How is Centralization Achieved? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30 Some Important Advantages/Disadvantages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36 How Much Cement is Needed for Isolation? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37 The Benefit of Swirl (Spiral Flow) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39 Durability and Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Wear in Microns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Stop Collars – the neglected issue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .49

Rev. 01/2002

ii “Proprietary - for the exclusive use of BP & ChevronTexaco”

Table of Contents

Cement Manual

Section 3: Cement: Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 What is Cement? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Manufacture of Portland Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Chemistry of Portland Cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Cement Hydration or 'How does it Work?' . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Limitations of Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Brief History of the Use of Cements in Oil Wells in the USA . . . . . . . . . . . . . . . . . . . . . . 10

Cement Slurry Design: Slurry Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 The properties which are generally considered to be important include: . . . . . . . . . . . . 35 Cement Slurry Mixing Water Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Quality of the Mixing Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Density . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Fluidity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Controllable Setting Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Sufficient Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 No Permeability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Long term durability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 The Use of Cement by the Oil Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Cementing Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Adjusting the Water Concentration to Change Slurry Density . . . . . . . . . . . . . . . . . . . . . 43 Effects of Extreme Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Other Special Conditions, Systems and Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Deepwater Situations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Guidelines for Selecting Flow Migration Control Slurries . . . . . . . . . . . . . . . . . . . . . . . . 60 Scale-Down Laboratory Test Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Cement Sampling, Blending and Quality Control: Dry Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Aim: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Steps for Successful Cement Blending . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Inspection of Bulk and Blending Equipment to be Used in the Operation . . . . . . . . . . . . 71

Table of Contents

iii “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Section 4: Displacements: Displacing Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 The Displacement Problem in a Nutshell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Fluid Incompatibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Rheological Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Minimization of Channeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Erodibility Technology: Wellbore Condition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 The Phenomenon of Free-fall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21 Optimization of the Displacement Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25 The Importance of Pipe Movement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27 Modeling the Displacement Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29 Example of a Job Simulation: A Slim Hole Situation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 The Real World . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38 On Site Data Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .50

Service Company Cementing Software: Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51 Schlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51 CemCADE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51 Computer-Aided Design and Evaluation for Cementing . . . . . . . . . . . . . . . . . . . . . . . . .51 Halliburton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 OptiCem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56 A Primary Cement Job Simulation Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 BJ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59 CMFACTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59 Primary Cement Design, Analysis and Real-time Monitoring Program . . . . . . . . . . . . . .59

Mud Preparation and Removal: Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .61 Wellbore Conditioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .61 Different Mud Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Cementing in Oil Based Mud (OBM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63 Cementing in Water Based Mud (WBM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65 Contnation of WBM with Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .66 Engineering Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .69

Rev. 01/2002

iv “Proprietary - for the exclusive use of BP & ChevronTexaco”

Table of Contents

Cement Manual

Section 5: Cementing Operations Design Process: Design Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 This provokes the question “What constitutes success?”. . . . . . . . . . . . . . . . . . . . . . . . . 3 What are the major risks to achieving the objectives? . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 The Risk Assessment Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 .....................................................................9 Cementing Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Personnel Competency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Guidelines for completion of the assessment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Appendix Additional Information: Publications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Guidelines, Check Lists . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Cementing Equipment – Operations Check List . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Cement Sampling Check List . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Offshore Platform Cement Unit Specification: Design Philosophy and Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 HSE Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Guidelines for Setting Cement Plugs in Horizontal and High Angle Wells: Plug Setting Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Plug Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Slurry Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Mud Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Cement Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Job Execution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Setting a Kick-off or Abandonment Plug in Open Hole: BP Alaskan Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Table of Contents

v “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Abandonment Plug . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19 Kick-off Plug . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19 Keys to Success . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19 Minimum Requirements for Cement Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20 General Pumping Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21 Abandonment Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21

Final HTHP Guidelines Key:

Index General Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Rev. 01/2002

vi “Proprietary - for the exclusive use of BP & ChevronTexaco”

Table of Contents

Cement Manual

Section 1: Overview

Special Considerations Introduction Understand some of the cementing issues presented by: • HPHT • Deep Water • ERD • Horizontal wells • Coiled Tubing Jobs • Multilateral Wells Examine several special situations which place particular, and often very critical, demands on the cementing operation, seriously impacting not just the slurry and spacer systems design, but also the execution of the job, placement equipment and techniques.

Cementing High Pressure - High Temperature wells (HPHT) Cementing under conditions of high temperature and/or high pressure is often required in deep wells and/or wells drilled into environments that present high temperature gradients. Deep HPHT wells have been drilled in many areas, for example South Texas, the North Sea and Middle East . Extreme cases of elevated temperatures include geothermal wells in California and Italy. In other areas, for instance the Caspian Sea, pore pressures are high requiring very high drilling fluid and cement slurry densities, but the temperatures are in not extreme. In any of these applications – high temperature or high density - the cementing operation requires considerably more attention to detail. The conditions are such that even minor overlooked details can cause failure. The lower tolerances associated with HPHT wells are extreme. Under normal well situations the same details may not present serious problems. Furthermore, the consequences of job Overview 1-1 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

failure are normally more severe than for ‘normal’ wells. This is due to the technical difficulties of drilling and completing these wells and the often elevated costs of such operations. The best, most experience personnel and resources must be brought to these wells. ‘Train-wrecks’ in HPHT cementing operations are usually caused by simple things overlooked or by a complete, total, lack of knowledge about some critical aspects of the operation (you don't know what you don't know). Of all the aspects connected with a cementing job, an accurate knowledge of the well temperatures is normally considered one of the most critical. In HPHT wells, temperature is, without question, the key to success of the job. Laboratory design of the cement slurry and spacer systems needs to be done way ahead of the job, using realistic well temperatures. As drilling continues and better information is obtained, the lab designs need to be refined using exactly the same cement and batches of additives that will be used on the job. Another aspect often associated with HPHT wells, is the narrow pore pressure/fracture gradient window. Accurate knowledge of this is vital for correct job design. Additionally, realistic simulations of surge and swab pressures to estimate casing, or liner, running speeds and break circulation are essential. An HPHT cementing operation should include contingency planning for situations that require unexpected cement jobs. For example, sidetracks, losses or casing shoe squeezes. The slurry and spacer designs need to be tested well ahead of time. It can easily take a week of laboratory testing to achieve a slurry design which can be mixed and pumped with confidence at high temperatures. The best possible quality cement must be used, and the additives must be selected for the elevated temperatures of the job. Sensitivity testing to temperature is needed on the critical properties of the cement slurry such as thickening time, fluid loss, free fluid, rheology and compressive strength development. This is to cover the uncertainty normally associated with well circulating temperatures. Slurry and spacer systems need to be kept simple, eliminating the use of additives that are not strictly needed to fulfill the goals of the design (for example, the need to be able to control gas or water invasion after cementing). Since elevated temperatures accelerate chemical reactions and effects considerably, compatibility studies between the drilling fluid, spacer system and cement slurries must be carefully conducted ahead of time. Rev. 01/2002

Overview 1-2 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Cementing in Deep Water Cementing in deepwater presents unique problems to the drilling engineer. Rig costs are so high, that that the timing of each operation essentially controls the cost of the well. The selection of techniques used to drill the well is driven by the high cost of time. Thus, reducing that time becomes extremely important. Likewise, reduction/elimination of failures is essential. For example, it costs around US $300,000/day for a deepwater rig. If, for example, waiting on cement time could be reduced for a given operation from say 12 hours to 8 hours, the cost of drilling the well would be reduced by around $50,000! By the same token, reduction of failures is of the utmost importance since, again, costs accumulate rapidly. If it becomes necessary to repair (squeeze) a casing shoe, the cost of that repair could easily approach or exceed one million dollars. In deepwater, typically a 30 inch or 36 inch conductor casing is jetted to about 200 ft below the mud line (BML). Next, a 20 inch or 26 inch surface string is cemented using an inner string method, with the returns being to the ocean floor.

Deepwater Surface Casings and Shallow Water Zones

T

Water Sands

Figure 1: Typical Deepwater Shallow Casings Configuration Courtesy of BJ Services

Overview 1-3 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

While drilling the surface holes of these wells in the Gulf of Mexico and other parts of the world, formations shallower than 2,000 ft below mud line can be weak and unconsolidated. In addition, shallow, highly pressurized, water containing zones may be encountered. The presence of these shallow, pressurized water zones is quite hard to predict even with the use of shallow seismic methods. These complex situations, if not handled correctly, can easily lead to the occurrence of high water flows through the cemented annulus of the shallow surface casing. Shallow water zones with pore pressures of around 9.5 lb/gal equivalent may require (depending on the depth where they are encountered), as much as 12 to 14+ lb/gal mud density to control them. Operators have experienced pore pressures as high as 12.6 lb/gal very close to the mud line. Very severe water flows have been experienced. It has been reported that flow rates as high as 30,000 barrels per day are possible in some deepwater locations. In these extreme situations, the shallow water flow rates can be so high , that they can generate washout craters large enough to seriously jeopardize the integrity of the well. There are documented cases in the industry where uncontrolled shallow flows have practically "swallowed" the entire multi-well template, at a cost of millions of dollars to the operator. In addition to the potential for shallow water flows, these deep water wells present other complicating problems such as: • shallow gas, • cool temperature profiles down the riser and at the mud line - often approaching freezing temperature for water, • narrow window between the pore and fracture pressure, • large washouts in big holes • hydrates To control shallow water flows and the other complicating well conditions, special techniques and cement slurry designs are used.

Rev. 01/2002

Overview 1-4 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Figure 2: World Areas Experiencing Shallow Water Flows

Shallow Water Flow Areas

Confirmed Flow

Potential Flow

No Reported Flow

Courtesy of BJ Services

The basic approach to cementing across shallow water zones consists of: • maintaining control of the water zones while drilling • properly preparing and treating the hole before cementing to avoid the onset of water flows • cementing the annulus using spacer fluids and cement slurries that maximize the potential for inhibition of the flows after cementing. To accomplish this, sacrificial muds are sometimes used to drill the zones (these are muds which are lost to the seabed since the riser is not yet connected). The drilling fluids will have some fluid loss control and tailored rheological properties to minimize the formation of progressive gels and of thick, mushy mud films across permeable weak zones. This is done to facility mud removal during the cementing operation.

Overview 1-5 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Spotting fluids are sometimes placed across the entire annulus, or across the lower critical zones, before pulling the drill pipe. These fluids are designed to maintain hydraulic control across the water zones, and may include some setting properties to assist in cementing annular areas that may not be fully covered with cement during the cementing operation. They will not set so well, or as hard, as cement nevertheless can provide a barrier to flow. The cement slurries used are specially designed and tested to be able to control the shallow water zones. Most of the currently used cement systems are foamed. Foamed slurries can be mixed at different densities using the same base slurry design. This flexibility is needed to be able to rapidly and easily adjust the slurry density to the levels needed to control the water zones. Foamed systems have great sweeping properties to facilitate displacement of the mud and/or spot fluid from the large annuli. In addition, they posses the ability to control water and gas flows by their capacity to maintain elevated pore pressures in the cement column while it goes through the transition stage. The cement slurries are often preceded by foamed spacer systems to again aid in displacing the well fluids. Shallow gas may also be encountered while drilling the shallow sections of deepwater wells, but generally is not so problematic as that of the shallow water zones. In general, the same cement slurry formulations and placement techniques needed to control the shallow water flows, apply to the control of shallow gas. The cool temperatures and the necessarily low cement slurry densities seriously complicate slurry design. Temperature affects all the properties of cement slurries that are critical for deepwater cementing: rheology, thickening time, transition time, free fluid, fluid loss and strength development. Excessive thickening times are undesirable and the goal must be to eliminate or minimise WOC time. Transition Time is the time from when the slurry stops behaving as a fluid (full transmission of hydrostatic head) to the point when it develops a significant measurable rigidity. During the transition time of un-foamed slurries, the pressure exerted by the column decreases due to the generation of progressive gels which support part of the annular load exerted by the slurry. Rev. 01/2002

Overview 1-6 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

This pressure drop can allow influx of formation fluid or gas into the annulus. Short transition times are therefore necessary when cementing across shallow water zones. Again, foamed cement slurries, due to the presence of the Nitrogen phase, have the ability to maintain the pore pressure of the cement columns, reducing the risk of annular invasion.

Cementing Highly Deviated and Horizontal Wells Cementing highly deviated wells is somewhat more difficult than vertical, or near-vertical, wells due to the following factors: • The casing or liner is difficult to centralise, generally lying on the low side of the hole. This makes mud removal difficult. • Torque and drag considerations can make running a casing or liner to depth difficult • Cuttings beds can form during drilling. These may hinder getting the casing to TD. They can also act as a conduit for later flow and compromise zone isolation. • Highly deviated wells are often ‘long reach’ or Extended Reach (ERD), this means the Equivalent Circulating Density (ECD) can be high. Long section lengths create problems with cement channeling past the mud and mixing in the annulus. • As deviation increases, wellbore stability problems and the narrowing mud weight window can constrain job design • Concerns about barite sag can result in relatively higher mud rheologies which further constrain the cement placement. • The cement slurry has to be an extremely stable suspension with very little free water. Free Water will create channels on the high side which will compromise zone isolation. One of the main problems encountered while drilling and cementing highly deviated, extended reach and horizontal wells is the tendency of solids from all the fluids in the wellbore to settle on the low side of the hole. The Figure below shows the result of a large scale experiment conducted in a man-made wellbore. Notice the presence of the solids bed on the low side of the hole. To further complicate the problem, experiments have shown that solids beds on the low side of highly deviated and horizontal holes can quickly become immobile (dehydrated) across permeability, making their removal extremely difficult. Overview 1-7 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Research has shown that transport of cuttings in drilling muds becomes more difficult as hole angle increases. Hard solids beds have also been found on the low side of the inside of the casing. These ‘inside-casing’ solids beds are not always easily removed by the cementing plugs; in fact, cementing plugs damage has been observed in certain cases.

D e v ia te d /H o riz o n ta l W e lls • S t a tic /D y n a m ic S o lid s S e t tlin g • D if fic u lt to rem ove M u d S o lid s

Figure 3: Solids Settled on the Low Side of an Inclined Hole Courtesy of Halliburton Services

It can be seen that minimization of solids settling from the drilling fluid while drilling the hole is critical to the success of the cementation of these types of wells. Another problem is the tendency of the casing to rest on the low side of the hole. Across doglegs, the string may even rest against the high side of the well, depending on the direction of the normal forces generated in the wellbore. Because of this, to get good cement jobs, it is critical to use proper centralization. Minimum stand-off should be around 80 to 90% + at the lowest casing point (i.e. between centralizers). Fortunately, specially designed centralizers have been developed that are capable of reducing drag and torque in these wells, while still providing good centralization for the pipe. The most recent developments include rollers to effectively "roll" the pipe to bottom.

Rev. 01/2002

Overview 1-8 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Settling of solids from the cement slurry and spacer fluids is also a serious potential problem Therefore, the slurry and spacer used in these wells must be non-settling statically and dynamically at downhole conditions. The Free Fluid of the cement slurry must be zero at downhole conditions, particularly if gas or formation water migration is a potential problem in the well. An unstable mud or cement can lead to a blow out in these wells. Estimating well circulating temperatures to design the cement slurries can be a challenge for these wells. To estimate the well bottom hole circulating temperature (BHCT), a bottomhole static temperature (BHST) and/or the temperature gradient in the particular area is used. For vertical holes, the BHCT can be calculated using API published formulas or temperature charts. While the API method is the accepted standard for estimating BHCT, the correlations were developed before deviated drilling was common. Factors such as hole size, pipe size, surface temperature, water depth (for offshore locations), mud type, pump rates, etc., vary from well to well and can have an affect on the actual BHCT. Most of the wells investigated to develop the API temperature correlations were vertical. Thus, for highly deviated, extended reach and horizontal wells, the API correlations should not be used. Other methods to estimate the expected well temperatures are available. In extreme ERD wells, the BHCT can become close to the BHST at the TVD. If we compare two wells with the same true vertical depth (TVD), one vertical and the other with a horizontal section, the BHCT of the horizontal well will be hotter due to the high constant temperature along the horizontal section. On the other hand, if we compare two wells with the same measured depth (MD), one vertical and one horizontal, the BHCT of the vertical well will be the hotter because it sees higher temperatures at the bottom of the hole. One of the best ways of obtaining the BHCT of highly inclined and horizontal wells is using downhole temperature recorders specially designed for this purpose. One of the available designs consists of a memory recorder that can be tripped into the well with pipe or can be dropped down the drillstring during a cleanup trip. The tool measures the temperature at the bottom of the hole versus time. Once retrieved, the tool is connected to a portable computer and a graph obtained. This can be used to estimate BHCT but it should be born in mind that the geometry is Overview 1-9 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

different. In cementing the annulus is small and the pipe large. When the gauge is run in DP, the pipe is small and the annulus large. This can result in different flow regimes and different heat transfer results. However, with several of these BHCT measurements at different depths in a given field, a reliable BHCT correlation may be developed. Of course, on critical wells the cost of making these BHCT measurements may be acceptable; but it is often critical wells which have high costs and the time is not made available. Next to actual measurements of the well temperatures, software temperature simulators can be used to predict BHCT at any well deviation and geometry. Simulators are capable of estimating the entire temperature profile up and down the well, not just the BHCT. In long horizontal sections, due to the near constant temperature, the circulating temperature tend to be near constant too. The best way to use simulators is to first match measured temperatures from the well (such as log temperatures). This allows fine-tuning of the simulation to obtain a more reliable prediction of the BHCT temperature at the depth of interest. The Measure-While-Drilling (MWD) instrumentation can provide a temperature while drilling. The BHCT temperature obtained from MWD at the depth of interest is typically higher than the actual BHCT is during cementing, but it provides an upper limit to estimate the BHCT for cementing.

Cementing Extended Reach Wells In recent years, horizontal and extended reach drilling has made possible the exploitation of many otherwise sub-economic, or inaccessible, hydrocarbon horizons. Economic considerations have driven operators to continue to "push the envelope” to reach more hydrocarbon deposits per well, per pad, or per offshore platform. A major technical obstacle, with ever larger displacement wells, has been the increasing axial and rotational friction forces generated. Another complicating factor is the tendency for the pipe to rest on the low side of the hole, making centralization of the casing difficult.

Rev. 01/2002

Overview 1-10 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

E x te n d e d R e a c h Extended Reach sections

Horizontal A p p lic a tio n s well sections

B eiru te C o nsu ltin g

Courtesy of Weatherford

Figure 4: Extended Reach and Horizontal Well Sections

Overview 1-11 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Extended reach wells, by definition, present long sections of hole where the angle of inclination is high and essentially constant. These extended sections of hole can be many thousand of feet. It is not uncommon to find extended reach wells with measured depths of 15,000 feet or more. These extended sections further complicate problems like formation of solid beds, the difficulty of centralizing the pipe, etc. All of the comments made in the previous section on cementing highly deviated and horizontal wells apply to cementing extended reach wells. An additional factor can be the very high ECD’s which result from the pressure drop in the annulus in the long hole sections. This can impact displacement rates which, coupled with eccentric pipe, can lead to massive channeling of cement through the mud. This again emphasizes the need for a fully integrated approach to job design. The aims and requirements of the cement job need to be carefully set out and all the factors which might influence success addressed thoroughly. The mud, the hole condition, the pore/fracture gradient window, dog leg severity and many other factors will play a crucial role.

Cementing of Multilateral Junctions Multilateral wells are wells with branches from a main parent wellbore. The branches are often highly inclined, or horizontal, and multi-directional. When cementing multilateral junctions, two main aspects need to be considered: • selection of a cement system that will provide structural support and isolation at the junction. • the placement technique to displace the drilling fluid and to place the cement/sealant in the well. Both these aspects create severe difficulties in some types of multilateral well.

Rev. 01/2002

Overview 1-12 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Figure 5: Multilateral Wells

Many multilateral wells are drilled offshore Parent well may be a producer in the conventional way Multilateral well my be a re-entry well

For placement of the cement, industry "best practices" such as mud conditioning, centralization, use of spacer fluids, are all applicable and should be used. The selection of the appropriate cement system for a multilateral well can be affected by several factors specific to these types of wells.

These factors include: • Configuration of the multilateral hardware used to construct the junction • Stresses that will be applied to the cement during the life of the well • Junction sealing requirements • Composition, strength, permeability of the formation(s) in which the junction is placed • Types of fluids that the cement may be exposed to during the life of the well Because of the wide variety of requirements that can exist, no one single cement system is applicable in all cases. Furthermore, in some cases, there is no currently available cement which will provide the required pressure isolation at the junction. Thus, the selection of the cementing system needs to be done on a case-by-case basis. TAML Multilateral Well Classification The most commonly used classification of multilateral wells is the TAML classification. TAML (TechnologyAdvancement of Multilaterals) is a group of operators with multilateral experience who developed a categorization system for multilateral Overview 1-13 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

wells based on the amount and type of support provided at the junction. This categorization makes it easier for operators to recognize and compare the functionality and risk-to-reward evaluations of one multilateral completion design to another. Recognized TAML levels increase in complexity from Level 1 (simple open hole mainbore) through Level 6 as shown. Figure 6: TAML Multilateral Classification

Construction time: 1 day

Level 1

Construction time: 4 - 9 days

Construction time: 2 - 3 days

Level 4

Level 2

Construction time: 8 - 12 days

Construction time: 4 - 7 days

Level 5

Level 3

Construction time: 5 -10 days

Level 6

Level I Junctions: Open Hole Trunk—Open Hole Laterals In this case the Trunk is open hole. The laterals are also barefoot or slotted liners. Level I junctions are placed in consolidated, competent formations No cementing is involved in the construction of Level I. Level II: Cased Hole Trunk—Open Hole Junction In these wells the parent well is cased off and cemented, but the laterals are barefoot (open hole) with or without slotted liners. Level II junctions are also typically placed in consolidated formations. Again, no cementing is involved in the construction of Level II multilateral wells in the lateral hole sections. However, the cement sheath of the parent wellbore need to be considered when choosing a location for the window for the lateral section. Rev. 01/2002

Overview 1-14 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Many conventional cement systems are prone to crack and lose their ability to provide an annular seal during the process of milling a window, drilling the lateral, and constructing the junction. For these applications, non-conventional cement systems are available. For example, research has suggested that foamed cements with gas content between 18 to 38% by volume produce more ductile systems which are more likely to retain integrity. In laboratory experiments, foamed cement systems have been shown to withstand significant deformation and cyclical loading, showing no damage to the integrity of the cement matrix and experiencing minimal permanent deformation. Cement systems containing latex, and latex with fibers, have also been used. The primary benefit of the fibers in the cement is that they hold the cement together even after compressive load failure. This can help prevent chunks of cement from falling down into the parent wellbore during milling, drilling, and other operations conducted around the junction. Level III: Cased Hole Trunk—Mechanically Supported Junction For these applications, the mother-bore is cased off and cemented. The laterals are also cased, but not cemented. Level III junctions are again typically placed in consolidated formations. They have a non-cemented junction with no hydraulic integrity at the junction. The lateral liner is anchored to the mother-bore. Like Levels I and II, no cementing is involved in the construction of Level III multilateral wells in the lateral sections. Level IV: Cased Hole Trunk—Cased and Cemented Lateral In Level IV applications, both the main bore and the laterals are cased and cemented. They include a cemented junction. The junction does not require hydraulic integrity to be a Level IV junction, but some Level IV systems require hydraulic sealing at the junction. In this configuration, the cements used to cement the lateral section must maintain their integrity under conditions that cements used for conventional jobs are normally not subjected to. For this junction configuration, a window is milled and a lateral hole drilled. A casing string is cemented through the window to form the junction. The cement is then exposed to additional stresses when the junction is completed. For example, the completion process may involve milling off the casing stub that is left inside the parent wellbore. The milling process leaves a flush joint at the junction with the cement being exposed to the inside of the casing at the junction with the main wellbore. Overview 1-15 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Some of the physical and mechanical properties that the Level IV junction cement systems may need to possess include: • Acid resistance • Durability to exposure to various oils, synthetic oils, and other fluids • Impact resistance • Elasticity • Hydraulic bonding Impact resistance will generally be required for every Level IV multilateral junction system. The cement at the junction will be exposed to impacts during the completion of the well construction. Methods used to improve the impact resistance of cements include incorporating latex in the cement formulation. Foam cements have also been found to improve a number of the mechanical properties of cement systems. Conventional cement systems, while having high compressive strengths, are very brittle and prone to crack when loaded by impacts and/or internal pressure cycling. For conventional applications, this cracking of the cement may be acceptable because the cement is not always required to provide hydraulic sealing from within the casing, nor is the cement exposed to direct impact from drill pipe, tools, etc. while tripping in and out of the hole. However, for some multilateral configurations, the cement is relied on to help provide the hydraulic seal at the junction. Inspection of a model junction will soon indicate that this is unrealistic. In addition to the research to help the field engineer with the selection of the "best" cement systems to use in multilateral applications, work is ongoing to developed computer modeling capabilities (finite element analysis, etc.) to better predict the behavior/integrity of cemented sealed junctions when the well is loaded with various stress conditions (pressurized junctions, draw-down, etc.) and when exposed to impact loads.

Rev. 01/2002

Overview 1-16 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

One recent, novel technique that needs to be considered for Level IV multilateral wells involves the treatment of the formation surrounding the formation before or during the construction of the multilateral hole section with special, low viscosity resins. For the treatment to work, the formation needs to be permeable to be able to accept the resin. By injecting the material into the formation, the permeability can be reduced to essentially zero. Level V: Cased Hole Trunk—Hydraulically Isolated Junction In this type of multilateral application, hydraulic integrity at the joint is achieved by the mechanical completion used and not by the cement. The parent hole is cased and cemented. The lateral is also cased and cemented. Level V junctions are placed in consolidated and in unconsolidated formations. They have a cemented junction, but the cement is not necessarily relied on for hydraulic integrity at the junction. The junction has hydraulic integrity by way of some type of packer assembly. Level V junctions have main bore and lateral re-entry access. Level VI: Cased Hole Trunk and Lateral Level VI junctions are placed in consolidated and unconsolidated formations . They have a cemented junction, but the cement is not relied on for hydraulic integrity at the junction. The junction has hydraulic integrity. Level VI junctions have full bore access to the main bore and the lateral. Level VIs: Cased Hole Trunk and Lateral & Down-hole Splitter Level VIs junctions are placed in consolidated and unconsolidated formations. They have a cemented junction, but the cement is not relied on for hydraulic integrity at the junction.

Coiled Tubing Cementing Cementing operations performed with coiled tubing are mostly squeezing and plugging. The most common coiled tubing cementing application is squeezing off perforations which are no longer required. The well may then be re-perforated across another zone. Squeezing off perforations which have a high water cut is a common reason for such intervention.

Overview 1-17 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Squeeze cementing through coiled tubing (CT) is a relatively new operation in the petroleum industry. Interest in coiled tubing squeeze operations increased significantly with the success and cost savings generated in the Prudho Bay field, Alaska, in the 1980’s. Techniques and cement properties developed or identified by BP, ARCO and others for Alaskan North Slope operations served as the foundation for CT squeeze operations throughout the world. Squeeze, or remedial, cementing is a common operation in the petroleum industry throughout the world. Most squeeze operations are conducted with a drilling or workover rig, through tubing or drill pipe with threaded connections. Cement is the most common material used for squeezing and represents approximately 7 to 10% of the total cost of the squeeze operation. The rest of the job cost is related to well preparation, tools, waiting on cement (WOC), drilling out of excess cement left in the wellbore after the squeeze, etc. Squeeze operations using coiled tubing offer significant benefits for slurry placement, control of the squeeze process, and reduced squeeze costs. However, candidate selection and preparation, cement slurry formulation, and job design require special considerations to realize the full potential offered by the technique. A serious complicating factor is the reduced annular clearances often encountered when performing coiled tubing operations. Using CT can eliminate workover rig costs and significantly reduce well preparation and post-squeeze cleanup costs. Using CT in workover and squeeze operations has been successful in remote areas where rigs are not readily available or in areas where rig costs are high. Bringing a CT Unit to the well, performing a squeeze, cleaning out and reperforating can make money. Special techniques and material properties have been developed which improve the probability of success and realize the cost-saving potential of CT operations. The process of squeezing with CT is similar in many ways to squeezing through conventional threaded tubulars. Many of the general techniques for problem diagnosis, well preparation, and job design and execution used in conventional squeeze cementing operations apply to CT operations. However, there are some differences, and these differences can significantly affect the success of the operation. CT squeeze operations are essentially scaled-down squeeze operations: smaller tubulars and annular clearances, and generally smaller cement volumes. As with most reduced scale operations, attention to details is very critical in every aspect of the job. Rev. 01/2002

Overview 1-18 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Coiled tubing lends itself to plugging operations because it allows the operator to place small volumes of slurry in the wellbore more quickly and inexpensively than with conventional plugging procedures. Well pressure control can be maintained at the surface through a stripper and blowout preventer (BOP) so it is possible to run into a live wellbore, and the production tubing and wellheads do not need to be removed before the job. The tubing can be reciprocated during hole conditioning. Temperatures in the wellbore for CT operations can be significantly different from temperatures in conventional squeeze cementing operations. Downhole temperatures are affected by many variables including the type of fluid pumped or circulated, fluid density and rheological properties, volume pumped or circulated, rate of pumping, and the well configuration. Generally, the temperatures in CT operations are higher than in conventional squeeze operations with threaded tubing or drill pipe, primarily because of the lower volumes of fluid pumped and the lower flow rates used. However, with the larger CT workstrings, the temperatures may be closer to the conventional case. For most squeeze operations, and especially CT operations, accurate measurement of the wellbore temperature and temperature profile above and below the interval to be squeezed is necessary. Most cement slurries for conventional applications are tested using well simulation tests developed by the American Petroleum Institute (API). These tests represent a composite set of conditions, generally based on well depth, type of cementing operation and geothermal gradient. It is important to understand that none of the current API test schedules or procedures were developed from CT cementing operations. Therefore, job-tailored test procedures and schedules should be used to model the planned CT squeeze cementing operation as closely as possible to field conditions. Job related information needed to formulate job tailored test schedules include the following: Well temperatures (temperature is the most important variable affecting cement hydration.) Well pressure (pressure has a lesser effect than temperature on cement hydration but has a significant effect on fluid loss. Well pressures can be reasonably estimated from the hydrostatic pressure of wellbore fluids and the cementing fluids plus the expected surface pump pressure.) Overview 1-19 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Mixing equipment and procedure (the amount of time the slurry will be held on the surface before being pumped into the well can have a substantial effect on the thickening time of the cement, depending on the surface temperature, well temperatures and cement slurry formulation.). Batch mixing of the slurry is recommended, but the type of batch mixer and the way it is operated can affect the slurry properties. In some cases, particularly relatively small volumes of slurry ( 12 ¼”

10.

Pump balancing spacer to equalize hydrostatic differential due to lead spacer (1000’ of workstring capacity if possible)

11.

Displace with well fluid to 80’ above the calculated balance point.

12.

POOH at approximately 25 stands/hour to 300’ above the top of cement plug.

13.

Circulate hole clean the long way.

14.

Release wiper plug (optional)

15.

POOH

16.

Wait on cement before tagging or pressure testing (12 hours minimum from plug placement.)

Abandonment Requirements Well abandonment should proceed according to local regulatory requirements and conditions (See Article 2 “Abandonment & Plugging” Section 105 of the Alaska Oil and Gas Conservation Commission). Verify that AOGCC has been contacted for approval to set an abandonment or kick-off plug. Setting a Kick-off or Abandonment Plug in Open Hole -21 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Workstring Open Ended Drillpipe (Recommended) It is recommended that open ended drillpipe be used to place cement plugs. If a tubing stinger is to be utilized, then use the following guidelines for tubing stingers: Tubing Stinger Use a tubing stinger on the end of the drillpipe. The length of the stinger should be equal to or greater than the length of the cement with drillpipe in the hole. The length of the cement plug, and therefore, the minimum length of a stinger, can be calculated using the following equation: Length of cement plug = S/(D+A) Where: S = bbls of cement slurry D = capacity of tubing stinger (in bbls per foot) A = capacity of the annulus between the stinger and the hole (in bbls per foot) Tubing stinger diameter is dependent on the hole size. The smaller OD stinger will help minimize the disturbance to the cement plug as the drillpipe is pulled up out of the cement, although use of a stinger that is smaller than recommended will result in annular flow rates that are insufficient for proper plug placement. Coupling OD's of the tubing should be minimized. If no smaller tubing is available, 3 1/2" drillpipe may be considered. Use the following as a guide.

Rev. 01/2002

Hole Size

Recommended Stinger Size

17 ½” and larger

set plug with drillpipe

12 ¼” to 17 ½”

use 5” to 5 ½” stinger

9 ¼” to 12 ¼”

use a 2 7/8” stinger

6” to 8 ¾”

use a 3 ½” stinger

Less than 6”

use a 2 7/8” stinger

Setting a Kick-off or Abandonment Plug in Open Hole -22 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Support for Cement Plug The lack of a competent bottom could lead to an unstable plug system. When attempting to set a cement plug in open hole where there is no established bottom, one of the following procedures is recommended. Mechanical Bottom The use of a Mechanical device (i.e. Open Hole Packer, Parabow, Bridge Plug, etc.) is the best method to ensure that a stable bottom is in place to support a cement plug. When practical, this is the preferred and recommended method. Heavy Mud Spacer Placing a heavy mud spacer (equivalent to the cement plug density) between the bottom of the hole and the bottom of the cement plug is another method that will create a competent bottom for a cement plug. Use this method if the setting of a mechanical bottom is not practical. Viscous Pill When neither a mechanical bottom nor a heavy mud spacer can be used, a viscous pill may be pumped to provide support for a cement plug. This method is not as reliable as the other two methods but is usually the most practical. The length of the pill should be based on the volume of the pill mixing system on the rig. Pump as large a pill as is operationally feasible. There are two general recipes for viscous pills using either bentonite or N-squeeze. Typical Viscous Pill Water X bbls Bentonite 20-30 ppb Barite 50 ppb ( for 9.5ppg pill, may be more or less, depending on mud weight.) N-Squeeze specifications: Water X bbls N - Squeeze 25 ppb N - Plex 0.5 gal/bbl (while pumping) Barite 50 ppb ( for 9.5ppg pill, may be more or less, depending on mud weight.) Setting a Kick-off or Abandonment Plug in Open Hole -23 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Items to bear in mind with Viscous Pills are: •

A reactive viscous pill depends upon the reaction between calcium and bentonite. If the cement plug starts to drop, the calcium in the cement will immediately react with the bentonite to form a thick immovable barrier.

•

If a weighted spacer is required, then the freshwater should be viscosified with XCD or equivalent and weighted with barites. For OBM/POBM the spacer recommended on the cement program should be used. Typically, 20 bbl ahead of the cement and enough volume behind to hydrostatically balance the lead is used.

•

Ensure the mix water and any fluid remaining in the lines has a calcium level below 400 ppm with chlorides below 2000 ppm.

•

Treat the mix water with 0.5 ppb soda ash to remove the hardness and adjust pH to 9 by the addition of 0.5 ppb caustic.

•

Water based viscous pills must not be used for temporary suspension in OH when using OBM/SBM to prevent water wetting of formations.

•

The pill must not come in contact with any form of calcium on the surface or while being pumped down the drillpipe.

•

Typical rheological properties are: YP 50 lb/100 ft2, 10 sec gel 30- 50 lb/100 ft2

Volumes/Excesses Cement volume is critical to the success of a cement plug. Small cement volumes are consistently lost due to contamination. The minimum length of a cement plug should be 500’. The maximum length of a cement plug to be set in one stage should not exceed 1500’. Plug lengths greater than this increase the risk of the cement failing to fall out of the drillpipe as the drillpipe is pulled above the cement. It is preferable to use a caliper log to determine the cement volumes and to help decide where to set a plug. It is much better to set the plug in a section of the hole that is near gauge. The actual excess used should take into account knowledge of the particular area and hole conditions, e.g. sloughing shales or losses. If no caliper or site specific field data is available , the following excesses are to be used. Rev. 01/2002

Setting a Kick-off or Abandonment Plug in Open Hole -24 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Nominal Hole Size

% Excess (WBM)

% Excess (OBM)

36”

200

30”

100

17 ½”

50

20

12 ¼”

50

20

8 ½”

30

20

6 ¾”

30

20

6”

30

20

3 ¾”

30

20

Addendum to General Procedure for 2-stage Cement Jobs 11a. Batch mix or prepare second half of plug. 11b. RIH back to estimated TOC of first plug. Ensure that the workstring is washed down. Do NOT RIH without pumping. 11c. Repeat steps 5 through 12. Spacers Recommended spacer length is 1000’, but maybe less due to hydrostatic constraints. The tail spacer should be hydrostatically balanced to the lead spacer, i.e. 1000’ of the drillpipe capacity. Water Base Mud Systems In water base mud systems fresh water can be used as a spacer. KCL can be added for protection of water sensitive shales. Oil Base Mud Systems In oil base mud systems, 2 gal/bbl dispersant in water should be added to the spacer with mineral oil ahead of the lead spacer and behind the tail spacer. Also, diesel may be used if conditions permit. Weighted Spacers Use of a weighted spacer can be used if conditions require. Density should be 1 ppg over mud weight. KCL can be added for protection of water sensitive shales. 2 gal/bbl surfactant should be added for oil base mud systems. Setting a Kick-off or Abandonment Plug in Open Hole -25 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Wiper Plugs It is recommended to use a wiper plug to wipe the drillpipe after the workstring has been pulled above the cement plug and the well is being circulated. Running a wiper plug between the cement and the spacer is optional, but not mandatory. Wiper plugs help eliminate cement contamination in the drillpipe and help keep the cement isolated as it is being pumped down the drillpipe. This is the most important with small cement volumes. This will help to prevent downhole equipment problems when drilling resumes. Slurry Consistent slurry density and slurry volume is critical to a successful cement plug. Batch mixing of the cement is recommended. An additional 2 bbls of cement slurry should be mixed to make up for volume lost due to manifold piping in the batch mixer. The density should be checked using a pressurized mud balance. If a Recirculating Cement Mixer (RCM) is used, the cement should be brought up to weight before pumping. The mixing rate should be controlled at 2 - 4 bbl/min. For small cement volumes, less than twice the volume of the RCM, it can be used as a batch mixer. If the cement is mixed using a jet mixer, the cement should be dumped until a consistent slurry is obtained, then begin pumping calculated volume downhole. Slurry Design The design of the cement slurry is based on several factors. A slurry design must satisfy the following specifications: •

24 hr compressive strength sufficient at BHST of 4000-5000 psi

• •

Minimum 12 hr compressive strength at BHST of 3000 psi for kick off plugs.

•

Fluid loss 100 ~ 200cc/30 min at BHCT.

•

Zero free water to prevent high side channelling.

•

Thickening time – Calculated time to batch mix cement + pump the cement + displacement time + time required to pull drillpipe above the cement plug + 1 hr at BHCT. The cement blend varies depending on whether the plug is to be set for kick-off (17 ppg) or abandonment (15.8 ppg). Temperature of the well will determine how much retarder will be used to give the required amount of pump time and set up time.

Fluid loss is only required in plugs set across permeable formations in hole sizes of 8 1/2" or smaller, a fluid loss less than 150 ml is adequate for abandonment/suspension. However, less than 75 ml for squeeze slurries (coiled tubing Rev. 01/2002

Setting a Kick-off or Abandonment Plug in Open Hole -26 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

slurries are special cases and in house experience should be consulted), is recommended. Increased thickening times adversely affect compressive strength set times. When kicking off or tagging cement plugs it recommended to wait at least 12 hrs from plug placement or until a compressive strength test shows at least 3000psi. A cement dispersant should be used with care to maintain a minimum slurry yield point of 5lb/100 sq. ft. Cement Tests All cement blends must be tested. The following tests are recommended: •

Thickening Time - Perform a Thickening Time test of the blended cement to determine pump time of slurry. The thickening time test is to be performed at the bottom hole circulating temperature. The results of this test must be obtained before the cement is pumped.

•

Compressive Strength - Perform a 12 and 24 hr Compressive Strength test (UCA or Cubes) to determine when the cement will achieve adequate strength for tagging or kicking off from. Perform this test at the bottom hole static temperature. The results of this test are not required before the cement is to be pumped, although the test should be performed as soon as possible after the cement is blended.

•

Static Cup Set - A Static Cup set will be performed to on the cement slurry. This will reveal unacceptable Thixotropic characteristics.

BHST/BHCT The bottom hole circulating and static temperatures must be determined accurately. Reference the BHST/BHCT RP to calculate BHST/BHCT. Overestimated temperatures are a critical factor in plug failure. Temperatures should be included in the written plug procedure to avoid confusion when calculating slurry pump times and performing lab tests. Minimum thickening time should be job time plus minimum 1-hour safety margin. Temperature should be selected based on deviation and operation; it should also take into account local experience. Displacement Rates Maximum annular velocity is critical to successful plug placement. The minimum annular velocity should be 200 ft/min. These higher velocities will enhance mud removal and reduce contamination and channelling. In general, the cement plug should be displaced with the cement unit to ensure accurate control over displacement volume. The displacement can be accurately determined using a indicator sub. When an indicator sub is not used a slight under displacement is desired in Setting a Kick-off or Abandonment Plug in Open Hole -27 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

order to pull a dry string, typically 80’ of the workstring. For plugs deeper than 13,000 feet (~4,000m), the average ID of pipe should be determined to ensure correct displacement volume. In the larger hole sections where the cement pump is not sufficient to pump the minimum annular velocity, the slurry may be displaced with either the rig pumps or the cement unit pump. Rig pumps have a higher capacity, but are substantially less accurate than the cement unit pump. If placement is more important than rate, use the cement unit pump. Conversely, if the rate is more important than placement, use the rig pumps. Circulation Circulate hole until the mud is properly conditioned and the hole is free of cuttings, gas, etc. This may take 2 bottoms up or more. A clean hole will increase the chance of obtaining a successful plug. Pipe movement is one of the most influential factors in mud removal. Reciprocation and/or rotation, when feasible, will mechanically break up gelled mud and will greatly improve flow patterns in the annulus. Move the pipe when conditioning the hole and when placing the cement plug. Reciprocation This is the better method in straight holes and when the pipe is well centralized. Rotation This is the better method in deviated holes and when the pipe is poorly centralized. After setting the cement plug, pull back at least 300’ above estimated TOC and circulate at maximum rate. In addition to circulating at a high rate, either. dropping a wiper dart or pumping 50 bbl of 50 ppb Nutplug in active mud to clean pipe from cement rings is recommended. Tagging/Pressure Testing Plugs should not be tagged until they have at least 1000-psi compressive strength and 1500-psi compressive strength is required to pressure test the plug. Kick-off plugs will require a compressive strength of 3000 psi. Deep kick-off plugs, >12,000 feet (~4000m), across hard formations will require 4000 psi compressive strength. Compressive strength should be determined at a temperature mid way between static and the temperature used for designing the pumping time. Where a plug is being tagged with a kick off assembly, use minimum flow rates. Do not run back into a cement plug until cement has set. When tagging, do not run back into cement without any circulation. Rev. 01/2002

Setting a Kick-off or Abandonment Plug in Open Hole -28 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Drilling It should be assumed that the top and bottom 75 feet (~26 m) of a cement plug will be contaminated with the spacer and appear to be green cement. If large quantities of cement are observed when circulating well above top of cement, then it is likely that cement channeling has occurred, with even more contamination by the spacer. This will increase the chance of failing to tag the plug and/or obtaining a pressure test. When kicking off of a cement plug, care should be taken that the entire cement plug is not drilled up. If cement integrity is not there, leave the lower portion of the cement plug in place and place another plug above it using the other plug as a bottom.

Setting a Kick-off or Abandonment Plug in Open Hole -29 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Rev. 01/2002

Cement Manual

Rev. 01/2002

Setting a Kick-off or Abandonment Plug in Open Hole -30 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Final HTHP Guidelines Key

Question

Directed at:

Operational Phase:

See text at:

what experience does the Service Company have locally with HPHT wells? What experience do the individual engineers have with HPHT?

ServCo Engineer, lab staff, rig site cementers

Planning

2.1 - 2.3

What support is going to be brought in to ensure best available expertise will be available?

ServCo Engineer, lab staff, rig site cementers

Planning

2.2

How can the lab demonstrate that it has the expertise and resources that it needs for this type of job?

Lab staff

Planning

2.3

What commitment is there from the ServCo to provide a full cementing service with positive interaction with other service providers - eg mud, liner equipment, rig contractor, bulk supplier, etc - to provide more than a slurry and a pump?

Drilling Engineer and Serv Co Engineer

Planning

2.4

Question

Directed at:

Operational Phase:

See text at:

What are the roles and responsibilities of those who will provide input?

Drilling Engineer and Serv Co Engineer, including others, eg mud co.

Planning

2.5, 2.10

Is the rig equipment good enough and how will this be assured? How and when will the issues be addressed?

Drilling Engineer, Serv Co Engineer, rig site cementers, Drilling Contractor, bulk operator

Planning

2.6

Cement Unit - up to the job?

Drilling Engineer, Serv Co Engineer, rig site cementers,

Planning

2.6.2

What are the limitations imposed by the rig, logistics and weather?

Drilling Engineer, Serv Co Engineer, rig site cementers,

Planning

2.6.3

Question

Directed at:

Operational Phase:

See text at:

What are the most likely temperatures, how are (were) they obtained, what confidence can be placed on them, what can be done while drilling to enhance confidence and reduce uncertainty? Who owns the issue and understands it?

Drilling Engineer and Serv Co Engineer

Planning

2.7, 3.3, 3.6.1

Is there a clear understanding of the hydraulics risks involved - ie is there a norrow pore/frac. window? Does special attention have to be given to circulating fluid properties? Does the mud need special attention prior to pumping cement?

Drilling Engineer and Serv Co Engineer, including others, eg mud co.

Planning

2.8

How will the mud company and the cementing company work together to understand what can be done to optimise the cementing process?

Drilling Engineer

Planning

2.4, 2.10

Have contingencies been identified, is there a documented and agreed plan of what is needed, by whom and when?

Drilling Engineer

Planning

2.9, 5.7

Is everyone clear what the process is and how it relates to them? Are the interfaces satisfactory?

Drilling Engineer

Planning

2.10

Question

Directed at:

Operational Phase:

See text at:

Are there proper prcedures in place for sampling, sample protection and shipment

Serv Co Engineer, Company Rep.

Planning/ execution

3.1, 3.2

Are tests on rig samples consistent with tests on other lab samples.

Serv Co Engineer, Lab Engineer

Execution

2.3, 3.1

Check Batch Numbers on all materials

Company Rep, Rig site cementers

Execution

3.2, 5.3

Temperatures - is the circulating temperature(s) consistent with what is known? What uncertainty is there? To what extent could this affect what is being done?

Serv Co Engineer, Lab Engineer

Execution

2.7, 3.3, 3.6.1

Has a “brainstorming” session been held on the rig to address ways in which the job could be jeopardised? Have ‘actions’ from this been assigned?

Company Rep.

Execution

5.5

Contingency plans in place?

Company Rep.

Execution

5.7,

Displacement volumes, pump efficiencies, volume to bump the plug?

Company Rep.

Execution

5.12

Full, written job procedures?

Company Rep., liner running company, Cement ServCo Engineer

Execution

5.

CementManual

Index General Index A Adjusting the Slurry Rheology, 3-49 Adjusting the Slurry Thickening Time, 3-49 Automatic Sampling, 3-81

B Best Practices, 1-34, 1-75 Centralization, 1-76 Displacement Procedures, 1-75 Hole Conditioning, 1-75 Use of Erodibility Technology, 1-76 Use of Plugs, 1-75 Use of Spacers, 1-75 Blend Size, 3-69 Blending, 3-63 On the Fly, 3-79 Blending Equipment, 3-72 Blending Procedure, 3-68 Bulk Cement Equipment, 2-13 Bulk Equipment, 3-71

C Carbon Dioxide, 3-57 Casing Centralization, 2-25 CemCADE Cement Job Evaluation, 4-53 CBL Adviser, 4-53 Plug Cementing, 4-54 Post-Job, 4-54 Temperature Simulator, 4-54 Centralizer, 4-53 Fluid database, 4-52 Input data, 4-52 Laminar Flow Displacement, 4-53 Mud Removal, 4-53 Design, 4-53 Evaluation, 4-53 U-tube and placemen, 4-51 U-tube and placement, 4-51 Cement, 3-1 API Specifications, 3-11 Class A, 3-11 Class B, 3-12

Class C, 3-12 Class D, 3-13 Class E, 3-14 Class F, 3-14 Class G, 3-15 Class H, 3-15 History, 3-10 Light Weight, 3-18 Limitations, 3-9 Other Used, 3-16 Pozzolans, 3-16 Testing Slurries, 3-19 Dynamic Settling Test, 3-33 Fluid Loss, 3-21 Free Water, 3-27 Gel strength, 3-25 Settling Test Tube, 3-32 Strength Development, 3-28 Thickening Time, 3-19 Viscosity, 3-23 Trinity Lite-Wate, 3-18 TXI Lightweight, 3-18 Cement Blending, 3-66 Cement Heads, 2-15 Cement Hydration, 3-6 Cement Job Evaluation, 1-71 Cement Slurry Design Important Properties, 3-35 Cement Slurry Mixing Water Ratio, 3-35 Cementing Objectives, 1-66 Cementing Additives, 3-42 Cementing Equipment Selection, 1-33 Cementing in Oil Based Mud, 4-63 Cementing Program, 1-69 Channeling Minimization, 4-11 CMFACTS, 4-59 Features, 4-60 CO2 Carbon Dioxide, 3-57 Common, 1-49 Composite Sample Preparation, 3-83 Confirmation Testing, 3-84 Controllable Setting Time, 3-37 Controlling Slurry Fluid Loss, 3-50 Criteria for the Surface Casing, 1-66

D Data Collection, 4-50 Density of all Fluids Pumped, 4-50 Pump Rate, 4-50 Surface Pressure, 4-50 Data from logging tools, 1-77 Deep, Long Liners, 3-52 Deepwater, 3-59 Design Process, 5-1 ‘What constitutes success?, 5-3 major risks, 5-4 What is success?, 5-3 Displacement Job Simulation, 4-29 Displacement Modeling, 4-29 Accurate Geometry, 4-30 Fracture Pressure, 4-30 Pore Pressure vs. Depth, 4-31 Using Simulators, 4-29 Displacements, 4-1 Incompatibility, 4-2 Problem in a Nutshell, 4-1 Rheological Models, 4-5 Rheological Properties, 4-5 Dry Blending, 3-75 Dry Blending Calculations, 3-70 Dry Cement, 3-63 Durability, 3-41

E Effect of Magnesium Salt, 3-56 Engineering Recommendations Cementing Phase, 4-70 Drilling Phase, 4-69 Planning Phase, 4-69 Summary, 4-72 Equipment, 2-1 Automated Mixing, 2-5 Batch Mixing, 2-5 Bow Spring, 2-31 Casing Centralization, 2-25 Cement Heads, 2-15 Cement Mixing, 2-1 Cumulative volume pumped, 2-10 Float Shoes and Collars, 2-18 Flow rate, 2-9 High Pressure Lines, 2-11

Rev. 01/2002 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

Port Collar Operation, 2-23 Port collars, 2-22 Pressure, 2-9 Pumping, 2-6 Recording, 2-7 Rigid Centalizer, 2-32 Safety Considerations, 2-12 Slurry Density, 2-8 Solid Centalizer, 2-34 Stop Collars, 2-49 Surface and Subsurface, 2-1 Sweges, 2-15 Types of Centralizers, 2-31 Water Bushings, 2-15 Zeroing of the Scale Tank, 3-74 Erodibility, 4-13 Definition, 4-16 ECD Calculations, 4-20 Field Application, 4-17 Final Testing, 4-21 Wellbore Condition, 4-13 Evaluation of the Recorded Job Data, 1-76 Density record, 1-77 Job pressure behavior, 1-77 Other problems, 1-77 Extreme Temperatures, 3-52

F Fibrous Material, 3-52 Flaked Materials, 3-52 Flash Setting, 1-63 Float Shoes and collars, 2-18 Flow Migration Control, 3-60 Fluid Incompatibility, 4-2 Fluid Loss, 3-85 Fracture Pressure, 1-35 Free Fluid, 3-84 Free-fall, 4-21 Functions Of Spacers and Pre-Flushes, 4-68

G Geothermal Wells, 3-53 Granular Materials, 3-51 Guidelines for completion of the assessment, 5-13

H Halliburton, 4-56 HPHT, 1-1

I Increase Slurry Weight, 3-47 Adjusting the Slurry Rheolog, 3-49 Barite, 3-48 Hematite, 3-47 Manganese Oxide, 3-49 Information Transfer, 1-68 Interaction with Service Providers, 1-70 Isolation, 2-37

Standoff, 1-28 Manual Sampling, 3-82 Manufacture of Portland Cement, 3-2 Mud Conditioning Different Mud Types, 4-63 Engineering Recommendations, 4-69 Mud Conditioning and Hole Monitoring, 4-7 Mud Preparation, 4-61 MUDPUSH, 4-55

J

N

Job Evaluation Acoustic Logs, 1-74 Temperature Survey, 1-73 Job Simulation, 4-32 Example, 4-32 Fluid Properties, 4-33 Slim Hole Situation, 4-32 Wellbore Geometry, 4-32

No Permeability, 3-38 Non-Centralized Pipe, 2-26

L Less, 1-59 Liner Overlap Seal, 4-47 Liner Tiebacks, 4-49 Liner Top Packers, 4-44 Liquid Blending, 3-71, 3-78 Log Interpretation, 1-80 Combination of poor and good bond, 1-81 Continuous good bond, 1-80 Continuous poor bond, 1-81 Low side/high side, 1-81 Loss Circulation Control Additives, 3-51

M Magnesium Salt, 3-56 Major Factors Influencing Success, 1-25 , 1-25 API schedules for Thiickening Time, 1-31 Casing Centralization, 1-28 Flow Regime, 1-29 Mud Condition, 1-26 Mud Displacement Practices, 1-25 Pipe Movement, 1-27 Slurry Design, 1-30 Spacers and Flushes, 1-29

O OBM Drilled Solids, 4-63 Low-Shear-Rate Viscosity, 4-63 Viscosity, 4-63 OptiCem, 4-56 Change in viscosity, 4-58 Eccentricity, 4-57 Freefall, 4-57 Gas, 4-58 Mud compressibility, 4-57 Temperature dependant rheology, 4-57 Tuned Spacer, 4-57 Overview, 1-1 Deep Water, 1-3 Estimated job time, 1-20 Extended Reach Wells, 1-10 Highly Deviated and Horizontal Wells, 1-7 HPHT, 1-1 Multilateral Junctions, 1-12 Special Considerations, 1-1

P Particles to Lower Slurry Density, 3-45 Hollow Spheres, 3-45 Nitrogen - Foam Cements, 3-45 Personnel Competency, 5-11 Pilot Testing, 3-63 Pipe Movement, 4-27 Highly deviated and Horizontal Holes, 4-28 Liners, 4-28 Pore Pressure, 1-35

Rev. 01/2002 “Proprietary - for the exclusive use of BP & ChevronTexaco”

CementManual

Portland Cement Manufacture, 3-2 Post-Job Information, 1-76 Cement top, 1-76 Pressure Drop Across Liner Hangers and Polished Bore Receptacles, 4-43 Pressure Recording, 2-9 Problems Annular Pressure, 1-52 Cement "Flash Setting", 1-63 Failing to Bump the Top Plug, 1-49 Flow After Cementing, 1-59 Flow Through Unset Cement, 1-60 Gas Flow, 1-59 Gas Flow Through Microannulus, 1-60 Gas Migration, 1-59 Lack of Zone Isolation - Cross Flow, 1-51 Liner Tops that Fail Pressure Tests, 1-57 Low Leak-Off Test (LOT), 1-54 Low Top-of-Cement, 1-55 Soft Kick Off Plugs, 1-55

Q Quality Control, 3-63 Quality of the Mixing Water, 3-36 Controllable Setting Time, 3-37

R Reduce the Risk of Sticking the Casing, 2-25 Reverse Circulating, 4-44 Hole Size, 4-45 Job Execution, 4-47 Liner Cementing Considerations, 4-45 Liner Equipment, 4-47 Mud Removal, 4-46 Overlap Length, 4-47 Temperature, 4-46 Rheological Model Factors Affecting, 4-6 Selecting, 4-6 Rheological Models, 4-5 Risk Assessment Process, 5-5 Risk Register, 5-8 Roles and Responsibilities, 1-65 Planning, 1-66 Well design, 1-65

S

W

Safety Considerations, 2-12 Salts, 3-54 Sampling, 3-63 Sampling Liquid Blends, 3-83 Sampling of the Blended Cements, 3-81 Scale-Down Laboratory Test, 3-61 Schlumberger, 4-51 Segmented Ultrasonic Tools, 1-79 Quality of the Log Data, 1-80 Scanning Ultrasonic Tools, 1-79 Tool Selection, 1-79 Settling Test, 3-84 Slurry Density, 3-84 Slurry Design, 3-35 Density, 3-36 Fluidity, 3-37 Permeability, 3-38 Sufficient Strength, 3-38 Slurry Stability, 3-50 Sodium Metasilicate, 3-44 Sodium, Potassium, 3-54 Soft Kick Off Plugs, 1-55 Software, 4-51 BJ, 4-59 CemCADE, 4-51 CMFACTS, 4-59 Halliburton, 4-56 OptiCem, 4-56 Schlumberger, 4-51 Special Considerations, 1-1 HPHT, 1-1 Spiral Flow, 2-39 Sulfate Waters, 3-56

Water Concentration, 3-43 WBM Drilled Solids, 4-67 Viscosity, 4-67 Wellbore Benign hole, 4-38 Contamination in the Casing, 4-41 Difficult Hole, 4-38 Displacement Volumes, 4-42 Fluids Left Behind the Casing, 4-41 Hole Shape and Pressure Drop, 4-39 Job Monitoring, 4-42 Narrow Annuli, 4-42 Reactive Formations, 4-40 Shutdowns, 4-42 Wellbore Condition, 4-38 Wellbore Conditioning, 4-61

T Temperatures, 3-52 Thickening Time, 1-32, 3-84 Free Fluid, 1-32 Settling Behavior, 1-32 WOC Time, 1-33 Thixotropic, 3-58 Tools Available Sonic bond tools, 1-78 Ultrasonic Tools, 1-78

U Ultralow Temperatures, 3-54 Use of Cement by the Oil Industry, 3-42

Rev. 01/2002 “Proprietary - for the exclusive use of BP & ChevronTexaco”