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

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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

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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

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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

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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

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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

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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”

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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

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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


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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.

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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.


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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


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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”

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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.

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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”

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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.

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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


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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.

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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”

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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


Level 4

Level 2



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


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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”

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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.

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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.


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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


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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”

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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 (<25bbl), the actual properties of the slurry can be very different to the lab design. This can arise through the different magnitude and duration of shear imparted in the mixing process and to the heating involved. Beware of over-shearing the slurry in a batch mixer with a centrifugal recirculating pump. Expected pump-rate range (the time taken to pump the slurry down the CT to the interval to be squeezed determines the rate of heating experienced by the slurry. The heat-up rate is an important variable affecting the thickening time of a cement slurry.) Coiled tubing dimensions (the volume of the coiled tubing coupled with the pump rate can be used to design the thickening time test schedule for the slurry.) Planned pumping schedule and technique. Modified well simulation test schedules have been designed to simulate hesitation squeeze operations.

Estimated job time (including cleanout time for excess cement) The thickening time test for a coiled tubing cement slurry should model the well operation as closely as possible. It is necessary to duplicate the temperature, pressure, and pumping profile of the operations. For example, potential for hesitation should always be included in the design of a slurry for a squeeze job. This, is important to simulate the static periods for hesitation when the cement slurry (or other sealant) is not being sheared by pumping action. During these periods, the slurry may lose fluid and may develop gel strength, as the wellbore temperature begins to increase because there is no fluid movement to cool the wellbore. In most CT squeeze operations, some static or hesitation periods will occur during the pumping operation. These periods can dramatically alter the thickening time of the cement slurry.

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The API Operating Fluid Loss test is a filtration procedure performed to determine the amount of filtrate that can be removed from a slurry under specific conditions. This test is performed with a known filter medium, under 1,000 psi differential pressure and at the expected well temperature for the squeeze operation. For API tests, the filter medium is a 325-mesh, stainless steel screen. This screen has an effective permeability greater than about 1 darcy, and the entire filtration area is about 3.5 in2. For most cement slurry designs, the amount of fluid removed from the slurry in 30 minutes under the conditions listed above is the value of interest. However, for CT squeeze operations, the thickness or volume of filter-cake produced during the test is also of interest. Pressure applied during a CT squeeze is often higher than 1,000 psi, particularly when excess cement will be washed out to eliminate drillout cost and time. In these cases, the filter-cake must withstand the pressure differentials present in the wellbore during cleanout of excess cement before the cement has hydrated and developed strength. The permeability of the filter medium used in the API test is significantly higher than many formations, especially carbonates. In some test cells, core disks or synthetic (aluminum oxide) disks of varying permeability can be inserted in the cell by using an adapter. These adapters should be used when available, to better simulate well conditions during the test. For CT squeeze simulation tests, filtration time or the time of applied squeeze pressure usually exceeds the 30 minutes used during an API test. Thus, filter-cake volume produced under downhole CT conditions can be significantly larger than the filter-cake volume generated during an API test procedure at a single pressure. The API fluid loss cell does not have enough volume to accommodate all the filtrate generated from a CT in-situ test because of the extended time for squeezing and the higher pressures typically applied during CT operations. Cement slurries with filtrate volumes in excess of 60 ml will cause all the slurry to form filter-cake (become dehydrated) in the API cell. Modified methods for measuring fluid loss and filter-cake have been develop for CT applications.


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Rheological properties of the cement slurry are more important in CT squeezes because of the smaller diameter workstrings and slim annular configurations, placement conditions, and squeeze techniques. Solids suspension, flow properties, and gel strength development are of primary interest in designing cement slurries for CT squeeze operations. “Strength of cement” usually refers to the amount of compressive load the cement will withstand before failure. The compressive strength of a cement slurry can be determined by the API procedure in which an unconfined 2-in. cube (nominal dimensions) is compressively loaded (uniaxially) until the cement fails. This convenient method of compressive strength testing is similar to failure testing procedures used for construction industry practices from which the API methods were developed. The UCA (Ultrasonic Cement Analyzer) has the advantage of providing a continuous measure of compressive strength vs. time. This compressive strength is determined from correlations of sonic transit time vs. compressive strength, and therefore, the results need to be calibrated with destructive API tests. The mode of cement failure is tensile, or shear which is some 10% or so of the compressive strength. The API compressive strength test does not measure the strength of the filter-cake for squeeze cementing. Cement filter-cake density can be approximately 18 to 19 lbm/gal for a 15.8 lbm/gal slurry. It has been reported that some cement blends can build filter-cake compressive strengths of 5,000 psi before the liquid cement slurry itself has developed any measurable strength. Under most conditions, the compressive strength of the filter-cake from a squeeze cementing operation is two to five times greater than the compressive strength of the un-dehydrated cement. Durability of the cement is a concern in many CT squeeze operations. Portland cements are subject to attack by a variety of well fluids such as acid, certain components in formation waters, carbon dioxide, and others. To increase cement resistance to acid and some brines, latex has been used in the formation. Fly ash has been used to improve cement resistance to carbon dioxide.

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Regarding placement of the cement slurry, where possible, spotting cement across the interval to be squeezed is preferred. The general procedure recommended for spotting cement with coil tubing is listed below. This technique is designed to minimize contamination of the cement with the fluid in the wellbore. 1.

RIH to TD or below the squeeze interval.

2.

Begin pumping cement out the CT.

3.

Allow the top of the cement to rise above the nozzle at the end of the CT before pulling the CT string up.

4.

Pull the CT string out of the well at the same or a slower rate than pumping to permit the end of the CT nozzle to remain 5 to 10 ft below the top of the cement.

5.

For the last volume of cement, accelerate the CT pulling rate to allow the end of the CT nozzle to be above the planned top of cement.


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Major Factors Influencing Success Introduction The success of a cementing operation is influenced by many factors. In addition to the obvious ones of: • well geometry • well location • types and properties of the formations penetrated, • other aspects play a crucial role. We examine some of them here: • Mud displacement • Slurry design • Job planning and execution

Mud Displacement Practices To be able to properly cement the casing in the open hole, the drilling fluid used to create the open hole must be removed from the annulus ahead of the cement slurry. Most investigators agree that the following factors affect the process of mud displacement: • Mud properties to drill the hole, and mud conditioning prior to the cement job • Hole condition - non uniform, washed out hole presents special difficulties • Pipe movement - rotation or reciprocation • Pipe centralization • Fluid velocity - pump rate • Mud filter cake condition (erodibility) • Spacers and flushes • Cement slurry poperties Major Factors Influencing Success 1-25 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Mud Condition and Mud Conditioning Perhaps the most critical of the displacement factors is the condition of the hole and the mud prior to cementing – in fact, prior to picking up pipe. During hole conditioning, it is necessary to create a situation where the bulk of the mud is moving (circulating). Therefore, the goal of the conditioning process is to end-up with a “high mobility mud” across the entire annular length and cross-section. To achieve this, it is necessary, once the casing gets to bottom, to break and circulate all the pockets of gelled mud before the initiation of mixing and pumping of the cement slurry. For deviated wells, the low end rheologies (and gels) of the drilling fluid are normally higher than for vertical wells. The higher properties are needed to minimize solids settling from the mud on the low side of the hole while drilling the well. If solids settling from the mud is not prevented, a solids bed can form. These solids beds - either barite or cuttings - are very difficult to remove (see Figur), particularly across good permeability.

Courtesy of Halliburton Services

Figure 7: Solids Settling from Drilling Muds in Deviated Wells. A large Scale Experiment It is sometimes assumed that as long as the mud is “conditioned” (pumping of a reduced rheology mud, etc.) before the cement job, that the cement job will go well. However, as confirmed by large-scale experiments, if permeable zones are drilled with mud with poor properties (capable of developing thick, gelled, partially dehydrated, mud cake), it is extremely difficult to get the bulk of the mud in the annulus moving. In fact, there is evidence that pumping a high mobility

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(conditioned) mud in the hole during hole conditioning in this situation, may lead to channeling of the high mobility mud through the low mobility (gelled) mud. At the surface, the mud properties may look fine, giving a false indication that the hole is in good shape. In such a situation, the chances of getting a good cement job are reduced greatly. The answer is to ensure the zones of interest (pay) are never contacted by a low quality drilling fluid. The pay zones need to be drilled with a high mobility, good property drill-in mud that can be easily conditioned before the cement job. Pipe Movement A fairly straightforward and relatively simple technique to aid in the mud displacement process is to move the pipe while conditioning mud and, if possible, while pumping the cement into the annulus. Full-scale displacement tests have shown that simple pipe movement, either rotation or reciprocation, can improve displacement. Pipe movement helps remove gelled mud and assists in getting a competent, uniform sheath of cement all around the casing. • Pipe movement is often not a viable option in the following circumstances: • large ‘surface’ casing strings (bigger than 9 5/8”) • very long strings • high deviation wells or wells with high doglegs (DLS) • offshore wells fromdrillships or semi-submersibles. In near-vertical wells, during reciprocation the pipe tends to move from side to side of the hole and this helps break much of the gelled mud. For highly deviated and horizontal wells, the pipe may not move from side to side so well (around doglegs, for example). With reciprocation in highly deviated/horizontal holes, the pipe may get stuck on the upward stroke, potentially leaving uncased openhole. Reciprocation sometimes limits pipe movement to only pre-cement job conditions. In deviated wells, rotation has an advantage over reciprocation in that it tends to drag the fluids all the way around the pipe (better mud removal). With liners, reciprocation all the way to bumping of the plug has been used very effectively in near-vertical holes. Reciprocation is much better than no pipe movement, but regardless of deviation, with liners, rotation is preferred because it overcomes some disadvantages of reciprocation: Major Factors Influencing Success 1-27 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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• Eliminates the piston surge of the reciprocation downstroke. • Eliminates the swabbing effect of the reciprocation upstroke. • Eliminates the possibility of sticking the pipe out of position with respect to the desired setting depth. • It is less risky when the drillpipe and setting tool can be released from the liner prior to cementing. The best practice is to begin casing movement as soon as the liner reaches bottom and continue during hole conditioning and until cementing is finished. Rotation should be at least 10 to 20 rpm. Casing Centralization A well planned and executed centralizer program is one of the items on the “must do” list to obtain a good primary cement job, particularly in highly deviated wells. Displacement of the mud on the narrow side of the annulus will not take place if the pipe is close to, or against, the wellbore wall. Adequate centralization of the casing is essential to obtaining good displacement of the drilling fluid and proper placement of the cement slurry around the pipe. Whilst pipe centralization is sometimes – incorrectly - viewed as optional for vertical wells, it is a requirement for cementing under deviated conditions. If the pipe is not mechanically centralized, the pipe will lay on the low side, making it impossible to obtain a cement sheath that completely encircles the casing. Centralization of the casing helps provide a uniform flow path around the entire circumference of the casing so that the mud can be more readily replaced. Large-scale tests have shown that mud displacement efficiency is directly related to the degree of casing centralization. A standoff of 80 - 90% is recommended for cementing. A well designed and executed casing centralization program will also greatly assist in running the casing to bottom, and with moving of the pipe once on bottom. Special centralizers have been developed recently that reduce torque and drag during running and moving of the pipe. The type and number of centralizers, and their location on the pipe, needs to be optimized using industry available computer programs, particularly for highly deviated wells. Rev. 01/2002


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Fluid Velocity - Pump Rate/Flow Regime The velocity (rate) at which the various fluids are pumped during the conditioning of the drilling fluid and during the actual cement job is a major factor in achieving a good mud displacement and cement job. Oil industry experts agree as to the benefits of pumping fluids in turbulent flow. However, because of the viscous nature of most cement slurries, it is usually difficult to achieve turbulent flow without breaking down weak formations in open hole. If this is the case, cement slurries will be pumped in laminar flow. Extensive studies of the effects of fluid velocity (flow regime) have been made both in full-scale displacement studies and in actual wells. The majority of the results from the full-scale displacement studies have shown that the faster flow rates will provide better displacement efficiency. These results have been confirmed in actual field jobs where the percent open hole volume circulating was measured as a function of flow rate. It is now known that the higher flow rates provide better displacement efficiencies because higher flow rates generate higher shear forces in the open hole. The higher the shear forces (shear stress) on the hole, the more partially dehydrated-gelled (PDG) drilling fluid will be broken free and circulated from the annulus. Spacers and Flushes Spacers and Flushes are used ahead of the cement slurry to prevent mud contamination of the cement slurry (formation of thick masses), and to facilitate the removal of the drilling fluid. However, spacers are very difficult systems to optimize. Spacers must be compatible with two fluids, the mud and the cement slurry. In general, these are very incompatible with each other. Spacers are designed to “work chemically” with muds and cement slurries. Since every mud and cement slurry is different, spacers should be essentially “custom designed” for every job. It should not be assumed that a spacer formulation which worked with a previous field mud will also work with the present field mud, even if similar additives are being used. This is particularly important when designing spacers for oil-based mud systems. Major Factors Influencing Success 1-29 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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When designing or evaluating a spacer system, the following criteria should be used to maximize the spacer’s effectiveness downhole: • The spacer must be compatible with both the drilling mud and the cement slurry. • The spacer must be non-settling. • The spacer should have a density between that of the drilling mud and the cement slurry, when possible, to assist with mud displacement and to reduce chances of channeling. • If possible, the spacer should have a consistency between that of the drilling mud and the cement slurry to again help with mud removal. • When using oil-based muds, the spacer must contain surfactants for water-wetting the pipe and formation face, to enable the cement to bond effectively to those surfaces. • For best results, the spacer should be pumped at the rates needed to effectively remove the PDG mud films across the permeable faces in the open hole • Based on field experience, enough spacer volume should be pumped to achieve a minimum of 10 min contact time at the top of the pay, or to fill 800 to 1,000 ft of annulus, whichever produces the greater volume. • The spacer should possess fluid loss control.

Cement Slurry Design Considerations The cement slurry design for a given job needs to be specifically tailored to the particular requirements for the given section of hole to be cemented. Of the utmost importance is keeping the design simple; including only essential additives. If ‘book’ formulations from previous jobs are considered, they need to be very carefully re-examined to ensure they apply to the specific well conditions at hand. The cement, additives and field mixing water used in the laboratory to optimize the slurry design must be the same as to be used on the job (same batches). Cement quality is very important. A quality, consistent, API monogrammed cement should be used whenever possible. However, lower quality cements are sometimes used due to remote location and other factors including local government requirements. In those cases, laboratory testing needs to be even more rigorous. For example, sensitivity tests of the slurry design to temperature Rev. 01/2002


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should be performed, since the well temperatures that the slurry will see are not well known (margin of error is often +/- 10 to 15 degrees F for the BHCT). Properties that Need to be Measured for Slurry Designs To minimize the potential for job failures, the following properties should to be measured in the laboratory and reported for slurries to be used in the field: • Thickening time • Compressive strength development • Rheology • Fluid loss • Free fluid • Settling behavior • Expected WOC time

Use of API schedules for measuring slurry Thickening Time(TT) The thickening time of a cement slurry is a measurement of the time the slurry will remain pumpable at bottom hole circulating temperature and pressure. The API thickening time test schedules are “standard” based on generalized well designs (casing sizes, casing depths, pump rates, well pressures), and should be used only for preliminary designs, before details for the particular job are known. Once the details for the job are available: casing size, depth and mud density, as well as the projected pump rate, these parameters need to be used to calculate a job-tailored test schedule. With this approach, time to BHCT and maximum job pressure often differ from standard API Schedules. This difference between the “job-tailored” and the API Schedules may have a marked effect on the measured TTs for the slurries.


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Acceptable Values for Thickening Time: A criteria for acceptable thickening time values is needed, to minimize WOC times and the time cement slurry remains liquid after placement. A criteria often used is: Minimum TT = MEPT + 1 hour ( 2 for some jobs, 1/2 hr for plug jobs) Where: MEPT = Maximum Estimated Job Placement Time TT = Thickening Time If the cement slurry will be batch-mixed, the surface retention time (time in the batch mixer) needs to be added to the calculated minimum TT, but must be simulated in the laboratory at the expected surface mixing temperature and atmospheric pressure. Maximum TT acceptable is normally two to three hours above the Minimum TT. Longer maximum TTs may be acceptable provided compressive strength at the top of the cement column is developed within field acceptable WOC times. Free Fluid Free fluid is an important cement slurry property related to slurry stability. It should be measured as closely as possible to downhole conditions. The preferred value for free fluid is zero, particularly for highly deviated wells, and particularly if gas/brine migration after cementing is a risk. For nearly vertical holes, the maximum allowed free fluid should be around 1.0%, provided gas/brine migration is not a concern. Cement Slurry and Spacer Fluid Settling Behavior A very critical property of the cement slurry is its solids suspending ability, both during and after placement, particularly for highly deviated and horizontal wells. In these wells, solids in suspension have a much shorter settling path than they would in a vertical well. Because solids can settle out of a slurry while being pumped the cement slurry must have sufficient yield point at downhole conditions to prevent dynamic settling. After placement, the slurry must suspend the solids until it develops sufficient gel strength to support them while setting. The same comments regarding solids suspension apply to spacer fluids. For example, the spacer needs to suspend its solids statically to keep from grabbing drillpipe during liner cementing. Rev. 01/2002


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WOC Time The waiting on cement (WOC) time is best determined using an Ultrasonic Cement Analyzer (UCA). The UCA provides a nondestructive way to continuously monitor compressive strength development under downhole temperature and pressure. The test should also be conducted at the downhole T and P at the top of the cement column. The cement slurry should be pre-conditioned in a consistometer. The preferred practice is to run UCA compressive strength tests at both bottom hole and at the top of the cement column or top-of-liner conditions to determine the optimum time to resume operations in the well. Normally, operations should not be resumed until the cement has developed 500+ psi at the top of the column. It needs to be remembered that the UCA obtains the compressive strength from correlations based on the acoustic transit time of the cement. Often, it is found that the compressive strength estimates of the UCA are conservative when compared with destructive (crushed) compressive strength tests. However, the UCA estimate of the time for initial set (~50 psi strength) is often quite accurate.

Cementing Equipment Selection One of the important functions of the operating company engineer is to liaise with the service company to make sure that job failures will not occur due to equipment. Similarly, service company personnel on location need to be well trained and experienced in the particular operation at hand, and if possible, with the particular field conditions. Many jobs have gone wrong due to surface equipment failures, and/or human errors, easily attributed to lack of experience of the service company personnel. Since it is imperative for the cement slurry going downhole to have the same properties as the slurry designed in the laboratory, it is necessary for the slurry to be mixed at the correct density. The old mixing device "the jet mixer" should no longer be used to mix cement slurries. Modern mixing equipment with re-circulating, automatic density control and/or the high shear batch-mixers should be used instead. Major Factors Influencing Success 1-33 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Once the mixing operation begins, the only control the operator has over the cement slurry going downhole is the regulation of slurry density. The cement slurry is designed to have an specific solids-to-water ratio. Deviations from this ratio will affect the cement properties. Most slurries will entrain air during the mixing operation. Chemicals are available that eliminate serious foaming but do not always prevent the formation under shear of minute air bubbles. When a slurry density measurement is made with a balance that weighs the slurry under atmospheric pressure, these tiny air bubbles can cause an erroneous measurement of the slurry density. The more accurate devices are those which measure the slurry density under pressure (the pressurized mud balance). Pressurized density measurements during the job should be made to validate the accuracy of the radioactive densiometer or other continuous density measurement device being used in the job.

Access and Application of Best Practices Field application of industry best practices is essential to success. Many of the "best" practices have been developed in the field, and then validated through laboratory studies. Others have been obtained with the assistance of large scale laboratory investigations, and successfully applied to the field. It has been said that "one cannot apply what one does not know." In order to be able to apply the best practices to the cement job at hand, the engineer needs to have access to these procedures. One of the main goals of this manual is to provide the bulk of the accepted industry wealth of cementing knowledge to the engineer and field personnel. However, it will also be necessary for the interested personnel to search the literature and to read many key papers written by industry experts through the years, to help complete his/hers knowledge base. Some of the industry available best practices include the following, many of which will be treated in detail in other chapters of this manual: • Slurry and spacer laboratory design optimization • Cement and spacer dry and liquid blending • Cement and spacer field mixing • Job design optimization using computer simulators • Equipment selection • Hole conditioning • Field techniques for mud displacement and slurry placement Rev. 01/2002


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• Contingency planning • Cement job post-analysis • Cement job evaluation • Cementing in particularly difficult situations: -

Deviated/horizontal/extended reach

-

HPTH

-

Cool environments

-

Slim holes

-

Deepwater

-

Challenging muds

-

Difficult formations: lost circulation, rubble, etc.

-

Potential for gas or formation water flows

-

Off-shore

-

Remote locations

Knowledge of Pore Pressure and Fracture Pressure Data A cement job cannot be properly designed without accurate information of the pore- pressure, fracture-pressure profiles for the well (see Figure). As the well gets deeper, a good understanding of the window of operation becomes even more critical, since often the pore pressures and fracture pressures of the formations penetrated are closer together (narrower window). In deeper sections, it can become a real challenge to design the cementing operation such that the job is performed without loosing returns (fracturing) or without the well flowing during or after the cement job. The challenge for the engineer is always to perform the cement job within the safety window; making sure not to fracture the weaker formations, and not allowing the well to flow. It is also important to make sure that the hydrostatic head across the high pressure zones is higher than the pore pressures after the cement job is completed (static). This is important particularly when flushes (low density spacer fluids) are used ahead of cement. Computer programs are available from service companies and operators that allow the safe optimization of the job. Factors that are taken into account to safely design and execute the job include the well configuration, the volumes and density of all the fluids, the rheological properties of the fluids, and the flow rates to be used during the job. Major Factors Influencing Success 1-35 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Figure 8: Pore Pressure-Fracture Pressure Profile

Knowledge of the Well temperatures. The ability to estimate the temperatures experienced by slurries while cementing is critical. Temperature is the most important variable affecting cement hydration, and because of this, the need to accurately know the BHCT during primary cementing operations is normally well recognized. One of the first design parameters with any cement slurry design is placement time, which is governed by the expected pumping rates and the estimated bottomhole circulating temperature. The effect that different BHCTs may have on a given cement slurry design is hard to predict since it varies with the type of additives, temperature range, etc. However, in general, changes of 10°°F or above in either direction (+ or -) may cause some alterations to the design. Temperature changes of 20°°F or more will likely force modifications in the slurry formulations (different additive loadings, different additives, etc.)

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Circulating temperatures during actual cementing operations are difficult to measure and predict because they are affected by many variables. Since measurement of circulating temperatures while cementing is normally not done, the oil industry has used for many years, other means to estimate wellbore temperatures during cementing operations. Under Cementing Highly Deviated and Horizontal Wells in this section of the manual we examined several considerations regarding the estimation of well temperatures. The most common way of estimating bottom hole circulating temperatures for a well is the American Petroleum Institute (API) correlations. To estimate bottomhole circulating temperatures, the American Petroleum Institute (API) has used measurements of circulating temperatures near the lowest point of circulation with drill pipe in the well, prior to coming out of the hole to run casing. The API Subcommittee Committee 10 on Standardization of Well Cements has served over four decades as the focal point for gathering temperature information useful for cementing operations. Many of the data points used by the API came from wells where the drilling fluid was circulated for a sufficiently long period of time to allow the temperature in the wellbore to reach a near steady-state condition. Standardized thickening time test schedules containing temperatures for primary and remedial cementing operations have been prepared from these data sets. The temperature data in API RP 10B have been used by the industry for nearly two decades. However, be aware that temperatures for a given well during cementing, or during circulation with mud, with casing in the hole may vary (in some cases significantly) from the temperatures estimated by the API correlations. This is because the correlations are really "averages" (with associated errors) from all the available data. In addition, as indicated above, the circulating temperatures developed by the API came from data collected with drill pipe in the hole. As mentioned under Cementing Highly Deviated and Horizontal Wells, the best way to estimate the BHCT for critical wells is to actually measure it during a cleanup trip using downhole tools provide by the service companies. The Figure below shows one of the industry available temperature recorders. The tools have been used in many wells to better estimate cementing temperatures. Measurements from the tools can be used to fine-tune computer simulator predictions to be able to estimate the entire temperature profile seen by the cement slurry during the cementing operation. Major Factors Influencing Success 1-37 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Figure 9: Downhole Temperature Recorder

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Knowledge of Policies and Regulatory Requirements The US and other countries have regulations covering cementing operations. At least 43 of the 50 US states have regulations controlling the drilling and cementing of wells drilled for the production of oil or gas. These regulations include aspects like depth of casing seats, strength of the cement (mainly for surface casing), WOC time, volume of cement used, need to circulate cement to the surface, plugging and squeezing requirements, etc. For surface casings, the main emphasis of the regulations is the protection of potable waters. Many states also require that mineral deposits be protected from contamination with hydrocarbons. The Tables below lists regulatory bodies and some of the requirements in the US. Drilling offshore outside the US territorial waters is governed by the Mineral Management Service of the Department of the Interior (MMS). Since regulations and regulatory bodies change, it is very important that the current guidelines be periodically reviewed to make sure drilling operations and cementing practices follow the requirements established by each state and local bodies (city ordinances, etc.) More and more countries are developing regulations and guidelines for the cementing of wells. The Table list several countries that have drilling and cementing regulations. One part of the world that is working very hard to protect the environment is the North Sea, particularly the Norwegian sector. This area is basically a zero discharge zone, meaning that no materials can be dumped to the sea from drilling platforms. All drilling materials (cuttings, residues from tank washing, excess cement and cement additives, tank washing, etc.) are required to be transported onshore and disposed off using environmentally safe and approved methods. The use of only government approved or green label chemicals and materials is becoming wide spread in many areas of the world. Regulations for onshore locations are also becoming quite strict. For example, even oil drippings from engines and bulk equipment need to be collected and properly discharged in many onshore locations. In those cases were local regulations are non-existing, the operator uses best known practices and guidelines from other locations like the US to make sure that fresh waters are properly protected, and that hydrocarbon zones are effectively isolated during cementing and plugging operations. Major Factors Influencing Success 1-39 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Regarding permanent plugging of zones and abandonment of wells, regulations normally require the isolation, with cement plugs, of all potable waters, minerals and hydrocarbon zones. Cement plugs are set either across the zones, or at some length above and below the zones to create isolation in the wellbore. The length of the cement plugs normally includes 50 feet above and below the interval to be covered. Cement plugs are also required to cover all casing shoes, all perforated intervals and any other questionable portion of the well that may present potential for communication. Additionally, a cement plug of about 25 ft is required right at the surface of the well. The previous section on Cement Plugs discusses the topic of abandonment in a little more detail, and the Figure below illustrates the typical location of abandonment cement plugs.

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Taken from the SPE Cementing Monograph, 1990


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Figure 10: Taken from the SPE CementingMonograph, 1990


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Figure 11: Taken From the SPE Cementing Monograph, 1990

The Importance of Planning Detailed planning of cementing procedures from the initial well design stage to the actual execution is an essential key to success. It can be said categorically that the success or failure of the cementing operation will depend heavily on the effort, depth and vigor dedicated to the planing process. Planning is a time consuming, team effort. To assure a successful operation, team effort is essential. The team must include: • cementing service company specialists, • mud company - the mud and its properties are crucial to the cement job • operating company driling engineer in charge of the job, • drilling contractor, • equipment providers (casing jewelry, float equipment, stage tools, liner hanger, etc.) • geologist/geophysisist - a knowledge of the formation propeties is vital - eg, pore/fracture pressure, permeability, reactivity, washouts. Rev. 01/2002


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Communication and co-operation must be established very early among all involved. All personnel must apply the best known cementing practices from the start of planning. The team effort is also needed to handle all the quality control measures required at each stage of the planning process and during the job. At the Planning of the Well Stage Detailed planning of all the expected cementing operations and cementing contingencies (kick-off plugs, squeeze of casing shoes, etc.), must start with the planning of the well itself. Since cementing is the most important operation performed to provide a competent conduit of the hydrocarbons to the surface, facilitation of the success of the cementing operations needs to be an integral part of the planning. For example, selection of mud systems that can provide near gauge holes must also be evaluated. Another aspect that can negatively affect the potential for zone isolation is narrow annular clearances that make centralization and cementing difficult, if not impossible. All service company personnel must be consulted and made aware of the job requirements at the very early stages of the well planning process. They need to be allowed to provide input based on their expertise, and they need to be allowed time to initiate recommendations and testing of preliminary slurry and spacer/flush systems. Service company personnel that needs to be involved early include drilling fluid and cementing specialists and casing jewelry providers. They need to be talking to each other and with the company drilling engineers and geologists. Questions that need to be asked should included the logistics of the entire process. For example, can we centralize this casing with these hole angles, and with this mud in the hole? What problems can be expected, and what things can we adjust, or change, at this stage to help assure cementing success?


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The following information needs to be shared. Much of it is normally included in the well drilling plan: • Well configuration: casing sizes and weights, hole /bit sizes, casing depths • Project mud types, densities, expected rheologies • Cement tops • Expected well temperatures • Proposed tail and filler slurries densities and column lengths • Lithology information: formation types, strengths, etc. • Pore pressure/fracture pressure profiles • Expected times for drilling, proposed slurry and spacer designs and cement job executions Preliminary discussions with service company personnel need to be geared also toward determining the information that may currently be questionable. For example, the source of the estimated well temperatures must be examined to make sure that the data are reliable and that they can be used for the well at hand. Plans may need to be made to obtain the extra data. Responsibilities need to be assigned to specific personnel to gather information. Preliminary computer job simulations need to be initiated. These simulations need to be continuously updated as better information is fed into the planning process. While Drilling the Section During drilling a section, a wealth of information is obtained that will potentially affect the success of the cement job. For example, drilling fluid formulation and/or density adjustments are normally needed during drilling. Higher pressures than expected may be encountered, loses of mud may be experienced, sections of the hole may tend to slough, logging runs give better information regarding actual well temperatures, lithology, pore and fracture pressures, etc. This information needs to be periodically passed to the cementing specialists, since this data may cause changes in the design of the cementing fluids and spacer composition. Also, the actual execution of the job may be impacted by the drilling data such as pumping rates, pipe movement and centralization, volumes of fluids, etc. Fluid designs and job computer simulations need to be revised/updated as the information from the drilling is obtained. Rev. 01/2002


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We said above that the planning process is a team effort. It is also a dynamic/continuous/changing effort all the way to the job execution. At the Cement Job Design Stage As a particular cement job approaches, finalization of many details is needed. For this, a more detailed look at the requirements of the operation is based on all the information collected during drilling. Well temperatures are fine-tuned and fixed. Slurry and spacer densities are finalised. Laboratory tests are performed and the final formulations for the tail and lead slurry are decided on. Final testing is done with the cement, additives and field water to be used on the job. Spacer design is fine-tuned and final compatibility studies are done using a drilling fluid sample from the well. Final bulk equipment (transports, pumps, batch mixers, densiometers, data recorder, etc.) are cleaned, check for performance and readied for the job. A decision is made as to when the cement will be blended, and the way the blend will be laboratory tested for compliance with the design. Confirmation is made with the float equipment and casing jewelry provider to make sure the equipment will be ready and properly installed. If centralizers and scratchers will be installed on the rack, arrangements are made for the installation to begin as soon as the casing has been inspected and cleaned. Final decision is made as to when the cement and other materials will be brought to location Spotting of the equipment, and any other location related decisions (like location of source of water, volume of water needed during the job and for washing, disposition of excess cement, etc.) are finalized. While Running Casing Prior to running casing, planing meetings need to be held with all personnel involved to make sure that the operation goes smoothly, preventing breaking down of weak formations, and avoiding getting the casing stuck. Procedures for casing movement during cementing are revised. Liner setting procedures and contingencies are reviewed. A decision is made as to when the spacer and cement slurry mixing operations will start. Meetings are held going over the entire cementing operation, reviewing personnel assignments, to make sure everyone knows exactly what their responsibilities are. For example, who will be checking returns, personnel in charge of dropping plugs, who will be taking the cement samples and checking the slurry and spacer densities, etc. Major Factors Influencing Success 1-47 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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During casing running, running speeds need to be controlled and checked vs. the computer simulations for surge and swab pressures. Responsibilities are assigned to specific personnel to make sure the casing is run according to the pre-calculated speeds, paying special attention once the casing starts below the last casing shoe, and in particular as the casing approaches the bottom of the hole. Line testing pressures are decided upon based on the expected job pressures and the weakest pressure rating of the equipment (normally the cementing head). Planning for last minute contingencies is also done at this stage of the process. “What if?” scenarios are constructed. For example, what will be done if the well loses complete circulation once the casing is on bottom? What if the liner cannot be set? What if we do not see the pressure blip when the dart picks up the liner wiper plug? How much over-displacement (if any) will be pumped if the plug does not bump, etc. During and After the Cement Job Once the job is in progress, hopefully all possible situations have been reviewed and contingency plans are in place for any unexpected event. The job needs to be performed exactly as planned (rates, volumes, etc.). and all the data collected so that an effective post-analysis can be performed. After the job, the previously discussed plan for material balance is put into effect. Water volumes used are checked. Tanks are checked for leftover cement. Cement bulk volumes used are checked vs. volumes pumped, etc. The job is reviewed with all personnel involved, and discussions are conducted as to how the job went vs. the expected pressures, etc.

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Common Cementing Problems Introduction Understand some of the common problems associated with primary cementing operations and how they might be avoided One problem - failure to bump the top plug - manifests itself during the actual job. Other problems are observed after the cementing operation, while testing the job or during the life of the well. The severity and cost of these problem varies with well type and location.

Failing to Bump the Top Plug To minimize contamination of the cement slurry with the fluids ahead of it while being pumped down the casing, a bottom plug is used ahead of the cement slurry. Actually, it is now common practice to use several bottom plugs. For example, a bottom plug is used in front of the spacer, and another in between the spacer and the cement slurry. The first bottom plug pushes and wipes the drilling fluid from the casing walls as it moves down the pipe. The second bottom plug separates the fluids minimizing contamination, and also further wipes the casing. When the bottom plug lands on the float collar, a differential pressure is generated and the diaphragm or disk on top of the plug ruptures to allow the fluids to continue intto the annulus. Following the cement slurry, a top plug is used. This plug is solid, and also minimizes contamination of the cement slurry, but the main function is to cause and signal the termination of the cementing job by generating a pressure increase when it lands on top of the bottom plugs. Based on the casing size and depth of the float collar, a displacement volume to "bump the plug" is calculated. A few barrels before the calculated displacement volume is reached, the pump rate is slowed to make sure that the plug is not landed with excessive force causing damage to the casing or surging weak zones in the annulus (hydraulic hammer effect).

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On occasions, the plug does not bump at the calculated and pumped displacement volume. Possible causes include: • compressibility of the displacement fluid not included in calculations • errors associated with the calculation of the displacement volume due to casing actual volume somewhat different from the ‘book’ value • air in lines between pumps and the well head • assumptions about rig pump efficiency which lead to an over-estimation of ‘number of strokes to bump the plug’ • human errors during the monitoring of the volume being pumped • mechanical problems or failure of the devices being used to measure the volume (displacement tanks, pump efficiency, flow meters, etc.) Occasionally, the plug may bump early (before the total calculated displacement volume is pumped). This is clearly an indication of a serious human error or of a mechanical problem as outlined above. For example, displacement volumes have been calculated all the way to the shoe, instead of to the float collar. The plug not bumping may, or may not, present a serious problem. If it is not absolutely necessary for the plug to land, often the pumps are shut down after pumping the calculated displacement volume and the cement slurry allowed to set (WOC time). Another approach is to pump an extra one half the shoe-track volume (casing volume between he float collar and the float shoe) to see if the plug bumps. If not, again the pumps are shut down and the job terminated. This last practice is more common with the large casing strings. With the smaller sizes of casing, this approach needs to be used with extreme caution because of the reduced capacity of the casings, and the great danger of over-displacing (pumping displacement fluid around the shoe), causing what is called a "wet shoe" situation. A wet shoe will require a cement squeeze operation of the casing shoe. The end result of the top plug not bumping may be that more cement needs to be drilled inside the casing before drilling ahead. This is not near as serious as causing a wet shoe by over-displacing, so normally, under-displacement is preferred.

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There are situations, however, where it is necessary for the top plug to bump, for example if an external casing packer needs to be inflated, or if a hydraulic stage tool needs to be opened. In these cases the top plug not bumping can be a very serious problem. For these cementing jobs, a pre-agreed procedure needs to be on hand outlining actions to be taken. Obviously, calculations and metering devices need to be checked and double checked to obtain the best possible estimate and measurement of the displacement volume needed to bump the plug. A good rig will keep records of calculated and actual pumped volumes to pump plugs so that efficiencies can be confirmed and/or adjusted. Some callibration of rig pumps can be done by pumping from one mud pit to another but this does not take account of all the potential errors which can occur.

Lack of Zone Isolation - Cross Flow Even when using the best procedures and practices in primary cementing, there are occasions when zones are not fully isolated. There are many potential causes. If isolation is inferred from cement logs (CBL/VDL, USIT, etc.), the analysis of the logs must be complimented by a review of the job execution against the program and expected behaviour before deciding that poor isolation exists. Many times when the results of the analysis are not clear, the decision is made to produce the well to see if communication manifests itself in the life of the well, rather than endangering production by pumping cement (squeeze) near the productive zones. Factors which should be reviewed include: • Mud properties • Centralisation • Displacement rates – planned and actual • Returns during the job – downhole losses? • Cement properties • The density and volume pumped • Spacer Common Cementing Problems 1-51 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Sometimes during the life of the well, poor isolation becomes evident by the observation of communication between zones. It can be noticed by the production of water or gas from a nearby zone, or by noise logs detecting flow to a depleted zone, etc. In these cases, isolation can be regained by performing some type of repair procedure. The most common way to recapture zonal isolation is by performing an squeeze cementing operations. Squeeze cementing practices are discussed in detail in the Squeeze Cementing Manual. Where cross flow exists in an open hole section prior to cementing – perhaps due to an induced fracture and a loss and kick zone open simultaneously - every effort should be made to cure this before running casing.

Annular Pressure Sustained Annular Casing Pressure can be caused by several factors. One obvious one is poor displacement of the drilling mud in the hole during cementing, generating mud pockets and channels that eventually allow communication of fluids to surface. Another cause can be flow through a micro-annulus. Micro-annulus flow may occur after the cement sheath is damaged during drilling out of the liner top, or casing shoe, or by high pressure testing the casing after the cement has taken an initial set (this may include when conducting a Leak Off Test). Similar effects can occur if the cement is displaced with heavy kill weight mud and then a light weight completion brine is used. It has been shown in the literature that testing the casing with pressure differentials of 4,000 psi and above over the differential that existed in the well when the cement set up, will cause damage to normal cement formulations. Extreme temperature changes during production can also cause damage to the cement sheath, particularly if coupled with fluid density changes. In many producing wells this pressure is routinely bled-off and is not a major problem – high pressure, but small volume. In other wells it can be a serious problem requiring difficult and expensive intervention.

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Certain cement formulations (e.g. foamed systems) resist extreme pressure differentials and temperature changes better than others. If a conventional density cement is being used, one possible way to minimize damage during testing and drilling is to make sure the cement has had plenty of time to develop most of its ultimate strength before resuming operations. To ensure that the cement has developed sufficient compressive strength, accurate temperature data must be available when conducting compressive strength tests in the laboratory. When drilling highly deviated or horizontal wells, the determination of well temperatures can be much more difficult than for vertical wells. In addition, offshore, the temperatures will be affected by water depth, sea currents and other factors. Care must be taken to ensure that the cement has cured sufficiently before drilling out the liner top or casing shoe, or testing the casing. The cost of the additional WOC time will not be as significant as the cost of trying to repair and seal a cement sheath that has been damaged because of premature resumption of operations on the rig. Annular surface pressure is not an uncommon problem. The U.S. Department of the Interior, Minerals Management Service (MMS) has stated that, of the 14,000 producing wells offshore; some 11,000 exhibit sustained annular casing pressure. It may be noticed days, weeks, months or even years after the primary cement job. Fixing the problem is normally not an easy task since it is very hard, if not impossible, to pump even water down the annulus. In cases where it is possible to pump, several materials can be used to remedy the situation. For example, micro-fine cement and polymeric systems. The polymer formulations can be mixed at viscosities near that of water, but harden or greatly viscosify once in place. It has also been reported in some cases, that loading (lubricating) the micro-channels with water (pumping slowly until the channels are filled) has mitigated sustained surface gas pressure. If it is impossible to pump down the annulus, it may be necessary to identify the source of the gas, and perforate the well to cause a seal across and/or above and below the source. This repair method causes production shut-down, and is normally deferred until abandonment.


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Low Leak-Off Test (LOT) The Leak-Off Test is used to make sure that the casing shoe is capable of preventing communication behind the casing, and that it will withstand the higher mud densities needed to drill ahead. Casing seats are selected such that the casing shoe will be cemented across a competent formation. A good prognosis of the fracture gradient at the section TD is normally available and there may be offset wells with recorded LOT data to act as a guide. When the LOT is low (i.e. leak-off occurs below the expected equivalent mud density), several factors may be the cause: • Contaminated cement around the shoe. For example, over-displacing the top plug may cause a "wet shoe" or, in the case of no bottom plug and a short shoe-track, mud film pushed ahead of the top plug. • Long rat-hole below the casing may cause excessive contamination of the cement around the shoe – perhaps after the job but while still fluid. The cement falls through lighter mud which then channels upwards • Lack of centralisation at the shoe and a mud channel as a result In these cases, communication behind the casing may be taking place. This problem is resolved by performing a squeeze job of the casing shoe. This type of repair, when conducted correctly, is normally quite successful – but time consuming. Ever effort should be made to assess the reason(s) for the low LOT before performing a squeeze. It is also possible that the formations around the shoe (or exposed when drilling the shoe) are not as competent as expected. This is a much more serious problem since squeeze cementing will not solve the problem.

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Top-of-Cement Lower than Required Cement tops (TOC) can be roughly estimated after the cement job by back-calculating from the end-pressure of the job – low rate just before bumping the plug. More accurate estimation of the cement tops can be obtained from cement bond logs (CBLs) and/or temperature logs run within 24 to 36 hours of the job. If the top of cement is lower than needed, several things may have caused this. The more obvious one is not enough cement slurry used during the job. This may have been caused by human error or by a greater than estimated hole washout. Lost circulation during the job or cement fallback after the job may also cause cement tops lower than expected. For the conductor or surface casing, low top of cement is normally solved by using spaghetti string or small tubing to do a ‘top-up’ job. For deeper casing strings, a circulation squeeze job may be needed to circulate cement above the current cement top. Depending on well conditions, cement may be circulated taking returns from the annulus at the surface from a set of perforations just above the cement top, or two sets of perforations may be needed for the circulation squeeze job.

Soft Kick Off Plugs Soft kick off plugs can prevent sidetracking of the well. Several factors can contribute to this problem, but the key cause is contamination of the cement slurry during placement or after the plug is placed (plug migration due to density differences). Selection of the cement slurry formulation is very important for kick off plugs. Normally the cement is required to develop high levels of strength to allow sidetracking. Often the cement is expected to develop higher strength that the surrounding formations (of course, this is not always possible). Therefore, kick off cement slurries need to be resistant to contamination with the wellbore fluids. Because of this, densified cement slurries (low water concentrations and densities of up to 17.5 lb/gal without the use of heavy weight additives) are often used. These systems tend to resist contamination by developing good levels of compressive strength even when mixed with some mud systems. In all cases, contamination tests need to be conducted in the lab with the particular drilling fluid in the hole and the selected slurry formulation and adjustments made as needed. Common Cementing Problems 1-55 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Figure 12: Example of the Effect of a Water Base Mud Contamination on the 12 hrs Compressive Strength Development of Cement Slurries Cured at 230°F Percent Mud Contaminati on

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The need to use densified (low water ratio, heavy density cement slurries) complicates the placement of the kick-off plugs because heavier cement slurry tends to swap places with the lighter mud in the hole. Therefore, the best plug placement practices need to be used to protect the cement slurry from levels of contamination that would prevent sidetracking. This will often involve spotting some very viscous mud or using a mechanical device to give the plug something to ‘sit on’. Kick-off cement plugs are normally allowed to harden for 12 to 24 hours. When testing the plug, drill pipe with a bit is run in the hole and the plug is tagged and weight is applied. The time required to drill or dress off the top of the plug is used as one of the means to judge the quality of the plug. A good kick off plug may drill at a rate of around 20 to 30 ft/hr with a medium tooth rock bit and weight on bit (WOB) of around 1000 lb/in of bit diameter and around 50 rpm. When drilling a hard kick off plug, the cuttings should be sharp and angular. If the kick off plug is too soft for sidetracking, the normal procedure is to drill or wash to a point low enough to allow setting of another plug, and the plug placement procedure repeated. Often the second plug will work because the first one contributes to forming a base that minimizes migration of the second cement slurry.

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Liner Tops that Fail Pressure Tests Good cement jobs on liners often carry a higher risk of failure than a primary casing job. Among the risk factors are: • they are normally deeper jobs with issues of temperature estimation and slurry design • more complex downhole equipment that may fail to work properly • annular clearances are normally small • liners are hard to centralize, • pipe movement during the jobs may be limited • cement volumes are relatively small Sometimes liner cementing operations are further complicated by partial, or total, loss of circulation during the jobs. These losses are commonly caused by excessive equivalent circulating densities (ECD) across weak formations due to tight annular clearances across the open hole and in the overlap, and possibly by bridging of solids and/or drilling fluid filtercake across tight liner lap areas. Major flow restrictions are often found at the liner tops due to reductions in flow area around liner hangers and polished bore receptacles (PBR). Liner tops are tested using positive, negative or positive and negative differential pressures, depending on the well requirements. When the liner top fails a pressure test, this is normally a serious problem because, similarly to the situation of annular surface pressure after the cement job, it is very hard to impossible to pump into liner overlaps. A mechanical packer may be the best option.


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Several factors can contribute to failed cement jobs across liner tops (overlaps). A field survey conducted by a major oil company suggested the following possible causes of leaky liner tops: • Poor cement placement (channeling) around the liner in the overlap due to poor liner centralization, lack of pipe movement, poor spacer design, etc. • Poor cement placement around the liner in the overlap caused by tight clearances. • Lost Circulation during cementing due to excessive pressures ECDs, bridging of the liner lap, etc. • Not enough overlap (300 - 500 ft needed based on field experiences). • Contaminated cement in the overlap caused by not using enough cement on top of the liner, lack of centralization, improper spacer design, etc. Should aim for 500ft of cement ontop of the liner. • Immobile solids beds accumulated in the overlap due to tight clearances, and the aggravating presence of flow restrictions caused by the presence of liner hangers, and polished bore receptacles (PBRs). • Immobile solids beds accumulated in the overlap generated by well inclination. • Poor cement slurry design: over-retarded slurry, not using a gas migration control slurry, slurry settling, etc. • Not waiting on cement long enough for the cement to get a good set at the top of the liner. • Swabbing of the liner top, by using poorly planned well operations after the job, before the cement is set. • High pressure testing of the casing after the cement is set, damaging the cement sheath in the overlap, etc. Leaky liner tops may be repaired from the top if the overlap is capable of taking fluid. If not, perforating below the overlap or across the offending zone may be needed to shut off the source of the flow. A liner top packer would be a more common solution. Rev. 01/2002


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Less Common Cementing Problems Flow After Cementing Gas/water migration after cementing has been recognized as a problem in the oil industry for decades. Much work has been done to investigate the causes and possible solutions to this problem. Reduced hydrostatic head, particularly in tight fracture-pressure/pore-pressure situations and in highly deviated/horizontal holes, can make formation fluid migration control critical. A concise summary of the potential causes of migration is given below. Types of Gas Migration It is generally accepted that gas migration can occur through three basic mechanisms. Proper identification of the potential gas migration path in a given well is critical in devising a plan to prevent the problem from recurring in future wells. • Gas flow through mud channels and the mud cake-formation interface • Gas flow through microannulus and damaged cement sheath • Gas flow through unset (but setting) cement Gas Flow Through Mud Channels and the Mudcake-Formation Interface Gas flow through mud channels, which is sometimes referred to as long-term gas migration, occurs because of the following: Cement is pumped in place and the slurry gels, and then sets. During the setting process, the cement may go through a small amount of plastic-state shrinkage and/or may take water from any thick mud filtercake left against the permeability, or from bypassed mud (a mud channel), weakening and shrinking the filtercake. When this occurs, micro-cracks providing a flow path for gas migration may form between the cement and the mud filtercake or mud pockets. This problem appears in cases where the mud cake is relatively thick and/or when there is poor mud displacement. As gas flows through these micro-cracks, it begins to dehydrate the moist mud filtercake or mud pocket. As this dehydration continues, the crack gets wider, which allows more gas, which causes the crack to widen, and so on. Common Cementing Problems 1-59 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Figure 13: Example of Potential Gas Migration Through Mud Channels As gas flows through the channel, it can communicate up the annulus. Typically, this gas is not seen at the surface for several days, weeks, or even months. Gas Flow Through Microannulus (Pipe Interface) and Damaged Cement Sheath We already briefly discussed this micro-annular mechanism of flow when we talked about the sustained surface annular pressure problem. This mechanism can also cause inter-zonal communication down hole. Formation Fluids Flow Through Unset Cement Flow through unset cement has been studied extensively, and many publications have been written. This type of migration occurs when the overbalance pressure is lost in a cemented annulus before the cement sets (or develops enough gel strength to prevent invasion). The loss of hydrostatic pressure in a cemented annulus before the cement actually sets has been well documented and is illustrated in the following figure.

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Hydrostatic Pressure

C em ent F lu id

C em ent S e ts

C em ent G e ls

O v e rb a la n c e P re s s u re

C em ent H a rd e n s

F o rm a tio n G a s P re s s u re

T im e Figure 14:

Loss of Overbalance Pressure in a Cemented Annulus

The loss of hydrostatic (overbalance) pressure is caused by the combined effects of static gel strength (SGS) development and volume losses (primarily caused by fluid loss from the cement slurry to permeable zones). As the cement gels, it can support some of the hydrostatic (overbalance) load and it becomes self-supporting. When the overbalance pressure is reduced due to cement gellation to the point that the pressure in the cement column is nearly equal to the formation pore pressure, formation fluids can invade the unset cement annulus. The buoyant force on the gas bubbles in the annulus can cause the bubbles to coalesce and to percolate up the cement column (gas migration). If sufficient volume of gas percolates up the annulus, a permanent channel (or series of channels or micro-channels) can form and remain in the set cement. The cement can then exhibit a high permeability. Transition Time Laboratory research has suggested that gas can percolate through unset cement until the cement reaches a “safe” static gel strength (SSGS) of about 500 lb/100 ft2. After the cement reaches 500 lb/100 ft2 (Some experts use a minimum of 1,000+ lb/100 ft2), it is too thick for gas bubbles to percolate through.


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Figure 15:

Gas Flow in Cement vs. Static Gel Strength

Beyond 500 - 1,000+ lb/100 ft2 (or some other high value), gas migration through the unset cement can no longer occur. The time it takes for the cement to gel from 100 to 500 lb/100 ft2 has been defined by a service company as the Transition Time of the cement. A better definition of "Transition Time" is the time from the start of development of gel strength (the point when the cement stops transmitting 100% of the hydrostatic head above it) to the time it has developed 1,000+ lb/100 ft2 of gel strength. Before the industry had developed an understanding of the causes of gas migration, and before cement slurries were developed that can help control the flow, serious problems were encountered. Cases of blow-outs and fires are well documented in the literature. Nowadays the situation is much less common. When migration after cementing occurs, it is generally because the cementing operation was not well designed, or executed, or the potential for migration after the job was not correctly diagnosed. In all cases of gas or water migration after cementing, repair normally consists of determining the location of the source of the gas or water, and perforating and squeezing to seal off the offending zone.

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Cement "Flash Setting" The so-called "flash setting" of cement slurries during pumping implies a sudden and rapid setting. Normally, cement slurries do not flash set. A cement slurry flash set would be apparent from an unexpected, very fast and large increase in pumping pressure, leading to a premature termination of the cement job. Some cement slurry formulations known as "right-angle set" cements do set very quickly and go from a pumpable liquid to an extremely gelled, or set, state is just a few minutes. However, like any other cement slurry, these cement slurries are normally in place before the slurry gets to the point to where it right angle sets. An exception may be if the cement has be designed at a much lower temperature than experienced in the well or is pumped at a higher density than lab tested. Or, if the slurry was pumped (say) without the retarder. There are, nonetheless, some situations that seem as if the slurry has experienced a flash set. They include cases of contamination of the Portland cement slurry with materials that tend to cause severe chemical reactions with the slurry. For example, calcium aluminate cements have been used in some wells for reasons including very high temperature applications (e.g. steam floods). On occasions, Portland cement slurries have been used ahead or behind the calcium aluminate cements. It has happened that the two types of cement slurries have come in contact in the wellbore. This mutual contamination of the slurries has caused a flash set at the contaminated interface. Also, Portland-with-gypsum cement slurries, if incorrectly used at high temperatures, may also set very quickly. Finally, slurries formulated without fluid loss control, pumped in tight annuli, across highly permeable zones may dehydrate suddenly, abruptly causing the formation of a bridge of dehydrated cement solids across the permeable zones. This, at the surface, would again look as if the cement suffered a flash set.


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Roles and Responsibilities Aim: • Understand the roles and responsibilities of those who contribute to a successful job. • Understand the need for a multi disciplinary approach to achieve the optimum job.

The Well design Cementing is the one of the most important operations performed in well construction. In exploration/appraisal it can be vital to achieving the objectives with the minimum NPT and cost. In a development, the wells may never produce to their full capacity without good zonal isolation. Company personnel have a responsibility to coordinate the planning and ensure that cementing considerations are addressed at all stages of the decision-making process. Decisions made during the planning of the well can substantially impact the ability to achieve cementing success. Examples are: • do we really expect to be able to cement a very long string without losses into productive but weak zones? • Will the presence of washouts prevent properly centralizing and cementing above and below the productive zones? • Do we need to under-ream, or do we expect to get a good cement across the pay with only 3/8 inch clearance across 1,000 ft of liner? Answers to these, and other questions that affect productivity, will directly influence the final construction of the well.

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Planning a cementing program • The specific objectives of the cement job need to be clearly defined and understood by all involved in the planning and execution of the operation. For example, the cementing objectives for the surface casing to protect potable water zones will be quite different from the objectives of an intermediate casing that runs across zones with no potential for production. It is the obligation of the operator’s personnel to clearly and unambiguously transmit these objectives to the service company. It is the responsibility of the service company representative to make sure that the cementing objectives are always kept in mind while designing the cement slurry, spacer systems and the cementing procedures to be used.

• Clearly define the objectives • Communicate them • Check understanding, particularly the relative importance of the various objectives

• Identify and manage risks • Control costs • Monitor and document changes Clearly defined cementing objectives facilitate the design of the operation and facilitate the post-job evaluation. Success, or failure, of the job will therefore not be based only on bumping the plug, or not having mechanical problems during the job, but on meeting the previously established and agreed objectives. Below are a few examples of possible cementing objectives for a couple of casing strings. Cementing Objectives and Acceptance Criteria for the Surface Casing:

• Bring competent cement to the mud line (ML) to provide adequate structural support for the well.

• Isolate the potential loss circulation zone in the XYZ formation from +/- 225 to 255 meters from the rotary table (RT).

• Minimize WOC time to drill ahead. • Avoid loss circulation and/or cement fallback. • Obtain a competent casing shoe, confirmed by a leak off test (LOT), of not less than 10.5 lb./gal to allow drilling to the next casing point.

• Prevent shallow gas flow after cementing. • Cementing Objectives and Acceptance Criteria for the Production Liner: • Obtain a competent liner top seal, tested under positive and negative pressure (differentials to be selected later). Rev. 01/2002


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• Obtain good mud displacement efficiency and no channelling during the

• •

job, confirmed by comparing job recording (pressures, returns, etc.) vs. expected (simulated) behavior, and the location of the top of cement on top of the liner. Experience no lost circulation while cementing, preventing damage to the productive zones. Minimize fluid loss to permeability from the cement slurry, preventing damage to the sensitive productive zones.

• Obtain isolation of all permeable hydrocarbon intervals. • No flow after cementing. As the cementing job approaches, the cementing objectives for each casing string need to be reviewed, refined and updated, based on all the information gained during the drilling of the particular hole section. In addition, to defining objectives, major risks to achieving these should be identified and mitigation plans developed. Management of risk and control of costs should be evident in the approaches adopted.


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Information Needed by the Service Company The service company representative needs to have, in addition to the clearly defined objectives for each casing string, all the relevant information about the well to be able to deliver a good design and execution plan of the cementing job. It can be a serious mistake to hold important and needed information from the service company representative. Tight hole status is no excuse to withhold information, and secrecy agreements can be used to protect the information. The service company cannot address important cementing issues if he, or she, is not aware of the location of the pay zones, pore pressures, etc. The following is the minimum needed by the service company representative. For specific situations, this may be extended, Well configuration: casing sizes, grades and weights, hole /bit sizes, casing depths

• • • • •

Well trajectory Drilling Rig details Mud types, densities, expected rheologies Required tops of cement (TOC’s) Expected well temperatures – static, undisturbed geothermal temperature gradient Provisional tail and filler slurries densities and column lengths Lithology information: formation types, strengths, etc. Pore pressure/fracture pressure profile Potential loss and kick zones Anticipated drilling time curve

• • • • • • Offset data, experiences, reports • Any preconceptions about job type (e.g. inner string) or slurry, spacer design or job approaches (special equipment)

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The Cementing Program The cementing program is normally a part of the well Drilling Program and contains details of the likely cementing jobs and the planned TOC‘s. This document may not outline in detail how the objectives will be achieved. A detailed cementing program will be prepared by the cementing service company. This will include details of all slurry designs, spacers, pumping schedules, materials quantities and costs. It should include recommendations for all aspects which will have an impact on acieving the objectives. It should, for instance, include recommendations for centralization and displacement rates. Generation of a complete and effective cementing program is a team effort with active participation of operator and service provider personnel (drilling engineer, geologist, mud engineer, downhole equipment supplier, etc.). Again, as more information is obtained as drilling progresses, the cementing program must to be reviewed, refined and updated. Below is a list of items that need to be part of the detailed cementing program.

• Well diagram including proposed depths, casing and hole sizes, casing weights, MD & TVDs.

• Drilling fluids information: types, densities, rheologies, etc. Often, these sections are left partially blank until the detailed interaction with the service company representatives has taken place.

• Available well temperatures data and source (offset wells or from correlations, etc.)

• Fracture pressure, pore pressure data vs. depth. • Offset well information (when available) detailing problems experienced during drilling and cementing. Presence of high pressure zones, lost circulation, etc.

• • • • • •

Information on the lithology for the specific well: zones of potential loss circulation weak zones that may washout hole instability sections high pressure zones with potential for flow after cementing, etc. Cementing job objectives and acceptance criteria for each contingency casing string.

• Methods to be used to test/evaluate each cement job. Roles and Responsibilities- 1-69 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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• Mud conditioning procedures. • Casing running speeds. • Details of casing hardware (jewelry) to be used. Number and placement. • •

Often to start with, these sections are left almost blank until the detailed interaction with the service company representatives has taken place. Details of each cement job procedure including the contingency jobs. Often to start with, these sections are left almost blank until the detailed interaction with the service company representatives has taken place. Details of the cement slurries and spacer systems proposed: density, volumes, fluid loss requirements, WOC times, cement tops, etc. Often to start with, these sections are left almost blank until the detailed interaction with the service company representatives has taken place.

The interaction with the Other Service Providers In addition to the cementing service company, drilling fluid, casing hardware, rig contractor (offshore rigs bulk system & delivery) and logging personnel need to be included and consulted on items that require their expertise. For example, the cementing company representative needs to actively interact with the drilling fluid specialist and the operator’s drilling engineer to make sure the selected mud system will be optimised to facilitate the cementing operations. Likewise, consultation with the providers of hardware is needed to make sure the best equipment is being used for the given application. Their help is needed to simulate centralization and running of the casing (torque and drag forces) particularly in deviated and extended reach wells. Logging specialists need to be aware of the type of cement systems to be used, to make sure that cementing logs are run and interpreted correctly, etc. This is particularly true when lightweight, high quality slurries are used.

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Cement Job Evaluation Several methods used to evaluate cement jobs. These include: • Leak-off tests and Formation Integrity Tests – LOT/FIT • Acoustic logs – CBL/VDL, USIT, etc • Temperature logs • Final pump pressure – to estimate TOC • Job execution record analysis (pump pressure, fluid density & flow rate) • Leak Off Test (LOT) and Formation Integrity Test (FIT) After the cement is fully set, the shoe track and about 10 to 15 ft of open hole are drilled is preparation for a LOT or a FIT. The tests are performed to determine if the casing shoe job and the exposed formation are competent enough to support the increased mud densities needed to drill ahead to higher pressure zones (plus a safety factor to provide for protection in case of a kick). The LOT and the FIT tests are basically the same, but the LOT carries the pressure increase to the fracture point of the formation, while the FIT brings the pressure to a given point needed to drill ahead, without necessarily fracturing the formation.

Figure 16: Illustration taken from the Applied Drilling Engineering SPE textbook series. Vol. 2 Cement Job Evaluation 1-71 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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To conduct the tests, the mud in the casing is conditioned or displaced to new mud for the next section. The casing is closed at the surface (BOPs) and a good quality, low fluid loss drilling fluid is pumped down the well at a fixed slow rate, normally about 1/4 bpm, until the desired pressure is obtained or the well starts to take fluid, noticed by a departure in the observed pressure trend. The surface pressure and the volume of fluid pumped are recorded and plotted on Cartesian paper as the test is performed. The Figure illustrates the process. Once the desired pressure is obtained, or the well starts to take fluid, the pump is stopped and the pressure observed and recorded for 10 to 20 minutes. If the casing was tested before drilling the shoe track, the line of pressure vs. volume pumped should be plotted on the same graph. In the figure, the dashed line was plotted based on anticipated results from previous tests (expected behavior). This line and the casing pressure test line can be of great help when conducting and interpreting the LOT or FIT. As illustrated in the figure, the pressure vs. volume tends to fall on a near straight line. Point D, near the start of the test, can be used to estimate the mud's gel strength development (resistant to initiate movement of the fluid). Likewise, the slope of the early portion of the line can be estimated from the compressibility of the drilling fluid, or the early measured slope can be used to estimate the compressibility of the mud. For a good FIT, when the pump is stopped, the last pressure point should fall on the straight line. For a LOT, a point is reached (point A on the graph) where the data departs from the straight line behavior. At that point, the formation (or the weak cement job) starts taking fluid. The pressure at point A is known as the leak off pressure. Pumping is continued at the same constant pump rate after reaching point A, to make sure that leak off is actually taking place. After a while (point B), the pump is shutdown to observe the pressure decline. As a rule of thumb, about 0.6 barrels of a 9 lb/gal water base mud is required to increase the surface pressure by 1000 psi for every 1000 ft of a 13-3/8 in. casing. Values for other casing sizes are given in the Table below. For example, if 13-3/8 in. casing is set at 7000 ft, it should require about 8.4 bbls of mud after all the compressibility and slack have been removed from the system, if a surface pressure of 2000 psi is desired for a FIT. This test would require about 34 minutes if pumping at 1/4 bpm.

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Cement Manual

Figure 17: Pressure Increase vs. Volume Pumped. Low Density Water Base Mud Casing, in

bbl/1000 ft/ 1000 psi

13-3/8

0.60

10-¾

0.40

9-5/8

0.32

7

0.16

If a good LOT or FIT is obtained, drilling continues. If not, and the cause is a faulty cement job, a squeeze job may be performed to repair the shoe,. If the cause of the problem is the formation (weaker than anticipated and incapable of supporting the needed mud densities), normally a squeeze job will only temporarily solve the problem. In extreme cases, a drilling liner may need to be run and cemented to isolate the weak shoe.

Temperature Survey Cements, when they set, generate energy, or heat of hydration, due exothermic chemical reactions. The temperature increase thus caused can be used to locate top of cement (TOC) by conducting a temperature survey before the heat is dissipated into the surrounding formation. To obtain the best determination of the cement top, the survey must be conducted around the time of maximum temperature increase. This maximum temperature increase is generated at around the time that the cement develops its final set. One rule of thumb is that the maximum heat generation takes place at a time approximately equal to the time needed for the cement to thicken under downhole conditions multiplied by a factor of 2. For example, if the thickening time of a slurry is 2-1/2 hours, then the temperature survey should be run at about 5 hours after bumping the top plug. This rule of thumb is not 100% since it needs to be remembered that for long cement columns, the top of the cement column normally sees lower temperatures than the BHCT. Thus, it is not unusual to have to re-run the temperature survey again if the initial run fails to detect the cement top. On the other hand, if one waits too long, the temperature surge may dissipate and the cement top may not be detected. Cement Job Evaluation 1-73 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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A better rule of thumb is to run the temperature survey at the time when it is expected that cement top has developed an early compressive strength of about 50 to 100 psi. This places the emphasis on the behavior of the cement at the top of the column. Laboratory data from the Ultrasonic Cement Analyzer (UCA) at the conditions of the top of the cement column are needed in this case. In any case, if the top of the cement is not clearly observed from the temperature survey, waiting a few more hours and re-running the survey often yields a good cement top. A big disadvantages is the time delay required.

Acoustic Logs The evaluation of the quality of cement behind pipe after the cement has set is one of the most difficult operations on the well. The problem is caused by the fact that the current tools and interpretative methods are not accurate, and are subject to a great deal of individual interpretation of the data generated. This had lead to many myths, misconceptions and misuses of the instruments and methods available in the industry. Here we will not discuss how to run or interpret a sonic or ultrasonic log. That belongs in the Cement Evaluation Course. Instead, we will review the proper way to make use of the logs as a tool to help evaluate the cement job. The above difficulties with the currently available technology has generated different approaches to the evaluation of cement jobs. On one hand, some in the industry use the data generated by sonic or ultrasonic logs exclusively to evaluate the cement quality, without examining other important and relevant data. Others do not believe in the tools at all and do not run them. The best approach is, of course, somewhere in between the two extremes. The proper evaluation of the quality of a cement job should include sonic and ultrasonic logs, in addition to the examination of all the other information available to the engineer. The cement job evaluation approach described below includes the analysis of the data from all the different sources. These sources include the open hole log data, the actual cement job execution and performance, the formulation and properties of the cement used in the job, and the data from the sonic and ultrasonic logs. Each of these sets of information needs serious Rev. 01/2002


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consideration to increase the chances of performing an accurate evaluation of the job. In addition, the following data must be available:

• Open hole caliper ( preferred four/six arm caliper) • On-site data from the cement job, including pressures, rates and densities • Simulation of the expected behavior of the job Best Cementing Practices The first question to ask when attempting to evaluate the quality of the cement job is,

• was a serious effort made to use best cementing practices during the planning and execution? If the answer is ‘no’, then there is a good chance that the job did not produced good results, and this lack of attention to good practices may point, along with other pieces of the puzzle, toward a possible bad job. When investigating the use of best cementing practices, several issues need to be examined. For example: Hole Conditioning and Displacement Procedures: The application of good hole conditioning procedures and mud displacement practices is essential to the success. The actual use of these techniques varies with well conditions. If good procedures were used, this should imply a likely good job. Proper use of Spacers: The job record should show that quality spacer systems and proper spacer volumes were used. Lab data should indicate good compatibility with the cement slurry, the spacer and the actual location mud. If an oil based mud was used to drill the hole, the spacer should have been tested for it’s ability to water-wet surfaces. If all of this was done, this should suggest the potential for good cement job. Use of Cementing Plugs: A bottom plug ahead of the cement slurry should have been used. Another bottom plug ahead of the spacer would indicate that a good effort to minimize contamination of the fluids in the casing was made. No use of bottom plugs points to possible contamination of the fluids in the casing. The bigger the casing ID, the greater the chances of contamination of the cement slurry while going down the pipe. Cement Job Evaluation 1-75 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Casing Centralization: The centralization program should have been designed with a computer simulator, particularly for deviated wells, dogleg situations, extended reach, etc. Proper centralizer equipment should have been used. Centralization should have been designed for a minimum of 80% or better. If all the centralizers were actually run, that would indicate the potential for a good cement job. If the pipe was not centralized, a very poor cement job is the likely result. Use of Erodibility Technology: To remove the partially dehydrated-gelled mud against the permeability, were the spacer and job rates designed and executed with that purpose in mind? If the answer is ‘yes’, that points to the potential for a good job Pipe Movement, Use of Wire loop Scratchers, etc.: If other best cementing practices were also applied, for example, if the pipe was moved during mud conditioning and during the cement job, and even better, if wire loop scratchers were used to removed the gelled mud against the permeability, that should have helped obtaining a good job. Post-Job Information Cement top: If, after considering the actual cement slurry volumes pumped, and with the help of an accurate caliper log, the cement top is found (with the sonic logs, using back calculation from the final job pressure and/or with temperature log) at about the expected depth, this again suggests a good cement job. On the other hand, if the cement top is significantly higher than it should be, it is probable that channeling occurred, suggesting a bad job. If the cement top is lower than calculated, this may confirm a loss circulation problem that would be verifiable using the record from the job pressures data. Evaluation of the Recorded Job Data Current onsite data recording technology allows a complete record of the cementing operation to be obtained and displayed during the job. The record includes density of the fluids pumped, surface pressures and pumping flow rates. If the rate of returns is being measured, the record can also include that information. After the job, all the recorded data needs to be evaluated in detail. Rev. 01/2002


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Job pressure behavior: The analysis of the surface pressure signature can help determine if the job went well without loss circulation, channeling or inflow. It can also indicate if restrictions were present during the job. The correct analysis of the data includes comparing the record to the predicted values and trends, the onset and end of free-fall, etc. Density record: This record should be used to check if all the fluids were pumped at the designed densities. Cement slurry properties can be drastically altered if the mixed density is not within the design requirements. Normally, the cement slurry needs to be mixed at the desired density +/- 0.1 lb/gal. Other problems experienced during the cement job: The recorded data and the comments from personnel on the job, should be used to decide if other problems occurred during the mixing and execution of the operation. For example, problems with quantity and quality of the water getting to the mixing equipment, excessive amounts of cuttings and debris coming in the returns, pipe tendency to sticking, etc. Data from logging tools All these sets of data and information can only point to the possibility of a good, or bad, cement job. The information must be used with data from logging tools to come to an informed decision about the quality of the job. On the other hand, the cement evaluation logs are the only tools run to try to actually "measure" the condition of the cement behind pipe. Again, the reason for the necessity to look at all the data available is that the cement logging tools are not accurate, and are subject to individual interpretation. Other limitations of the tools will be discussed below.


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Tools Available Sonic bond tools: These tools have the capability of "measuring" the bond of the cement to the casing and the bond of the cement to the formations. The bond however is greatly affected by the well conditions and other factors that will be discussed below. The bond to the casing is inferred using the measurement of the sonic energy transmitted down the casing. The bond to the formation is qualitative and is implied by the characteristics of the formation signals received by the tool (variable density log). All of the tools except the segmented tools provide data that is omni-directional. This means that the data is averaged from all the signals received from around the entire circumference of the pipe. This is a serious limitation of these tools. The segmented tools however, provides segmented data for the casing bond. The following tools can be classified as sonic evaluation tools.

• Amplitude tools • Attenuation tools • Segmenting bond tool The amplitude and the attenuation tools are similar and essentially provide the same information. The amplitude tools provide energy transmission data while the attenuation tools provide data on the amount of dampening of the sonic signal. The segmented tools provide amplitude or attenuation at specific locations around the casing. Ultrasonic Tools: These tools measure the reflection of an ultrasonic signal as it passes through the casing and is reflected by the casing cement interface. Because these tools only give information on the condition of the cement-pipe interface, only the quality of the cement bonding to the casing can be inferred. This is a serious limitation of these tools, since often mud channels form at the formation-cement interface, and the tools cannot "see" that section of the annulus. The tools, however, are segmented and can provide the quality of the cement bond at many locations around the casing. The tools are claimed to be less sensitive to (but still affected by) the presence of a microannulus. The following are the types of ultrasonic tools available: Rev. 01/2002


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Segmented Ultrasonic Tools Scanning Ultrasonic Tools The segmented tools provide impedance data at eight locations around the circumference of the pipe. The scanning tools provide data at small segments of less than 1 mm. The data from around the casing is very useful when the well is deviated, where there may be channels on the bottom or top of the annulus and where there is potential for gas migration. Tool Selection The tool needed for evaluation of a cement job must be chosen based on well conditions and requirements of the evaluation. Most of the time, the tools should be run in combination to provide the best data for the analysis of the job. The table below outlines the application of the different tools available. Figure 18: Applications of Cement Logging Tools Condition

Sonic (omni-directional)

Sonic (segmented)

Ultrasonic (segmented)

Ultrasonic (scanning)

Casing Bond

Yes

Yes

Yes

Yes

Formation Bond

Yes

Yes

No

No

Gas

No

No

Yes

Yes

Microannulus

Very Sensitive

Very Sensitive

Sensitive

Sensitive

Low side Channel

Not specific

Large at the casing

Large at the casing

Small at the casing

Deviated High side Channel

Not specific

Large at the casing

Large at the casing

Small at the casing

Deviated Channel on casing

Not specific

Only Large Channels

Only Large Channels

Small Channels

Channel on formation

Not Specific

Not Specific

No

No


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Quality of the Log Data It is important that the data provided by the logs is of high quality. Many factors can affect this:

• • • • • • • •

Fast Formations Cycle Skipping/stretch Thin Cement Sheaths Casing thickness limitations Borehole fluids Gate Settings Transducer malfunctions Collection/presentation of the Log Data

It is important that the cement evaluation logs be run with and without pressure. The sonic tools are very sensitive to the presence of microannuli and ultrasonic ones are also to a lesser extent. If there is a substantial difference in the logs conducted with and without pressure, then it is very likely that a micro-annulus is present. Microannuli are frequently present in wells. They can form for a variety of reasons. They normally do not compromise the cement job, but make the evaluation of the job with sonic or ultrasonic tools more difficult. The presence of a microannulus is normally not a serious problem since flow is not likely or, if it takes place, is very small due to the large pressure drops required. Gas is more likely to be a problem than oil or water. There are other special considerations when evaluating a cement bond log. For example, soft formations can produce a low stress environment for the cement and allow it to lose tight contact with the casing creating a microannulus that affects log evaluation. Some Log Interpretation Comments Continuous good bond: If the log indicates good bonding all along the cemented interval and the formation signal is good (comparison with the open hole sonic log and the Gamma ray log is very important!), then the cement job is generally considered good, particularly if the bulk of the other information available suggests a good cement job. Rev. 01/2002


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Continuous poor bond: If the log indicates little or no bonding all along the cemented interval, then the job may, or may not, be a good one. The examination of the additional data will help decide the actions to take: ignore the log, or do a squeeze job? Combination of poor and good bond: As with the previous case, the other data available will help with the interpretation. In addition, detailed examination of the logs may indicate that, for example, the poor bond is always across permeability. This may suggest the presence of a soft mud filter cake. If good contact with the formation exists across the shale barriers (Gamma ray is used to determine the presence of the shales), isolation may still exist, and a squeeze job may not be needed. Low side/high side differences in the logs: If the wellbore is deviated, channels on the low and high side of the hole may be present. If the cement slurry exhibits free fluid, a channel would form on the high side of the annulus. The channel may exist along the entire cemented interval. If the low side solids in the hole were not removed prior to or during the cement job, a solids channel will be present on the bottom of the annulus. The use of the segmented tools can be valuable for determining the presence of channels on the top or the bottom of the annulus. If channels are detected, the next thing is to estimate the length of the channels, and to decide if isolation exists or if a squeeze job may be needed.


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Section 2: Equipment

Surface and Subsurface Equipment Surface Equipment Aims: An understanding of the equipment used in well cementing - both surface and downhole

Cement Mixing Cement mixing equipment has to be robust and fail-safe. It has to cope with a wide range of slurry densities and slurry types. It has to be capable of mixing continuously at relatively high rates (minimum 4 to 5 bbl/minute, or greater than 1 MT/minute) and at a constant density. It must be able to cope with variations in bulk cement supply. These are very demanding requirements and in the early days required skilled and experienced operators. Even today mixing can, and does, create problems. It is, unfortunately, not that uncommon for the slurry to go downhole at a somewhat different density from that designed in the lab. Early mixing consisted of a jet mixer, hopper, small slurry tub and a cutting table for sacks. The cementer operating the unit would vary the water going to the jets in an attempt to cope with variations in cement supply or blockages in the hopper. The slurry tub would contain only about a bbl of slurry so little homogenisation took place. This type of mixing set-up is still the default, fail-safe, method on many sophisticated modern units.

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

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Figure 1: Early Mixing Setup Problems with delivery of a uniform, consistent slurry at constant density lead to the development of recirculating mixers with a much larger holding tub and the ability to get better control of density before pumping downhole. These mixers still deliver the mix water through jets but the cement is fed through a knife gate which can be controlled by the unit operator. The cement and water meet with high energy and and the resulting slurry is ejected with some force into recirculating tank. Here the slurry is further mixed by paddles and there is provision to recirculate some of the slurry back to the mixing point in order to raise the density. Once density matches the target value the slurry is fed to to triplex pumps and downhole. While pumping, further water and cement are constantly being mixed and fed to the recirculating tank which now acts as an averaging tank, smoothing out fluctuations in slurry density.

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Figure 2: Recirculating Mixer In place of sacks most cement now comes to the well as bulk powder. In most land operations this bulk will have been pre-blended (dry-blended) with additive powders at the service company base and brought to the well in a bulk trailer. Offshore, it is usual for neat cement stocks to be held in rig silos (P-Tanks) and additives (usually liquid additives) added at the time of mixing. Both systems will usually involve a ‘surge tank’ which is essentially a small silo or bulk tank. This is used to provide a steady, near constant feed to the mixer and it is usually situated directly over it.


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Figure 3: Surge Tanks

Figure 4: Halliburton Skid Unit

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Batch Mixing Batch mixers come in many forms and sizes. All are basically tanks which will hold the slurry before it is pumped downhole. Some hold only 50 bbl; others are 100 bbl or more. They will usually be equipped with some form of agitation. This may be paddles, centrifugal pumps or compressed air. The main use is in liner and plug cementing; the advantage being that the slurry can be brought up to weight with all the additives, homogenised and even tested before being pumped. There is thus no variation in density or properties and there is more assurance for critical slurries that everything is optimised. Two aspects to be aware of: • Lab testing (particularly pumping time) should take account of the holding time on surface. Testing in the consistometer should include a period without application of temperature and pressure. • Centrifugal pumps, recirculating small volumes of slurry over a long time, can lead to heating and shear effects which can alter the slurry properties. The slurry may then behave differently to the lab design. This has been a problem with Coiled Tubing (CT) jobs where slurry volumes are often small (<25 bbl). Automated Mixing Increasingly, computer automation is being used to control mixing rather than relying on the cementer’s skill and experience with the knife gate and water valves. These systems can work well and reliably but a fall back system is good insurance. Computer systems are essential for foamed cement slurry mixing with nitrogen.


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Pumping High pressure pumping units, like the mixer, have to be robust and capable of highly reliable performance. The industry has standardised on triplex (three plunger) pumps. Most cementing units will use two banks of triplex pumps – 2 x 3 cylinders. These are fed by centrifugal charge pumps through spring loaded valves. The pumps are very ruggedly constructed, can easily be stripped and repaired and are generally very reliable. They can pump highly abrasive slurries across a full range of densities and rheologies. The pluger stroke can vary from 5 to 10 inches and the plunger diameter from 3 to 6 inches. By altering the sizes, the delivery capability of the pumps can be varied to cope with different circumstances but using the same horsepower of the unit – higher pressures/lower flow rate or higher flow rate/lower pressure.

A unit will usually deliver between 200 and 500 hydraulic horsepower (hhp). Rates of up to 8 bbl/minute at 500 to 1,000 psi are typical cementing parameters when pumping downhole using 2” treating lines.

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Both diesel and electric powered units are available. The diagrams below show the guts of the fluid ends of a Halliburton HT 400 unit.

Recording The variables of interest are:

• Slurry density • Flow rate • Pressure • Cumulative volume Equipment-2-7 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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These variables are rquired throughout the job – mixing, pumping and displacement. Where displacement is done by the rig pumps, either extra sensors have to be installed and hooked up to the cement unit recording device or the data has to be downloaded from the mud loggers. Any cement job should have the above parameters recorded to provide:

• Assurance that what was pumped was what was designed • Enable comparison between planned execution and actual – for example, the final pressure just before bumping the plug can give a rough check on the height of cement in the annulus and confirm the estimated TOC.

• Allow analysis of a job to determine root cause of failure – pressure can be particularly decisive in identifying problems

• Aid planning and optimisation of subsequent jobs – transfer of learning Slurry Density The main methods are:

• Standard mud balance • Pressurised mud balance • Radioactive densitometer • U-Tube densitometer The first two are non-continuous devices, measuring only a sample. The Pressurised balance is much preferred although if is considered awkward to use. The main reason is the considerable amount of air entrained in the slurry from the mixing process. There is little time for this to break out and a normal mud balance will give a reading which is ‘lighter’ than the downhole (compressed) density. A pressurised balance will give a true, downhole density. The latter two devices will give continuous readings and are, therefore, preferred. However, it is still good practice to use a pressurised balance during the job to check the reading being given by the densitometer. Rev. 01/2002


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Figure 5: Pressurised balance (top) and normal mud balance Jobs have gone seriously awry because the cementer worked from a densitometer which has drifted off calibration. In any case, calibration of these devices should be routinely checked. Flow rate If the cementing unit is being used for displacement, the flow rate will be taken from the downhole pump stroke counter, corrected for pump efficiency. If rig pumps are being used for displacement, then a separate flow meter is needed or the data has to be obtained from the mud loggers and tied-back to the job timescale. Flow rate is particularly useful when compared with pressure. Pressure Pressure can be recorded from a tranducer at the the downhole pump discharge and is also usually measured by a Martin-Decker gauge which records on a circular chart. Since the Martin-Decker is an old-fashioned clockwork device it often provides a record when the more sophisticated devices, or the recording media, fail.


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Cumulative volume pumped This can be calculated from pump rate and time and also from strokes and pump efficiency. If displacement is with the cementing unit, then the number of displacement tanks can be counted to give a good estiamte. In fact, where displacement volume is important – pumping plugs, spotting fluids, picking up plugs, seating darts, etc – the cement unit displacement tanks are the most accurate since they do not rely on assumptions about pump efficiencies. Displacement tanks do need to be calibrated like all other devices. Slight errors in the markings are cumulative. Although the markings are fixed at the time of manufacture, the unit may not be quite level.

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High Pressure Lines The high pressure discharge of the cement unit pump is usually connected to the cement head through a 2” diameter, rigid – but articulated – line called treating iron or Chiksan line.

Treating lines are subject to erosional forces when pumping at high rates and need periodic inspection to ensure satisfactory wall thickness. This is usaully done annually by an ultrasonic method. Threads should be checked with a gauge kit and magnetic particle methods are used to look for any cracking. Size

Maximum Working Pressure (psi)

Maximum Flow Rate (bpm)

1 ½”

15,000

4.5

2”

20,000

4.5

2”

15,000

8.5

3”

15,000

20


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Higher rates will wear faster and require more frequent inspection. An annual pressure test to 15,000 psi is also required. The standard union is FMC Weco type 1502, with a working pressure of 15,000 psi. This is an integral, or Non-Pressure Thread Seal (NPTS). Threaded connections are not permitted between a positive displacement high-pressure pump discharge and the wellhead connection. High pressure lines should always be chained down to prevent uncontrolled, violent whiplash in the case of a catastrophic failure.

Safety Considerations Cementing operations should be approached with a high precautionary awareness of safety issues. Particularly important are:

• • • • •

High pressures Pressure testing operations Bulk cement with pneumatic supply Dust – cement is highly alkaline and can cause serious burns to the eyes Slips, trips and falls – cement units can be wet, slippery and frequently require climbing

• Units are frequently noisey and communication of warnings can be difficult • Heavy equipment to be manhandled – cement heads, Chicksan lines Pressure awareness should cover both ends of the spectrum – high pressure/low volume and low pressure/high volume. Bulk tanks may be pressured to only 15-40 psi but the energy stored is considerable and should not be underestimated. Bulk tanks and lines should be subject to regular inspection and ultrasonic thickness testing. Lines, in particular, can become eroded by cement transfers. Always treat hatches with extreme care – how do you know there is no pressure trapped? Rev. 01/2002


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High pressure treating lines are often subject to considerable rough handling and can often spend long periods between detailed visual inspection. In any pressure testing exercise the treating lines should be chained down to prevent flying around in case of a test failure. Personnel should be excluded from the viscinity and warning signs erected. Wherever there is a chance of overpressure being applied there shoud be a pressure relief device – either some spring-loaded device or a bursting disk. Needless to say, such devices require periodic re-certification.

Bulk Cement Equipment Land wells in many areas are serviced by bulk trucks which bring pre-blended cement to the site for the job.

Off-shore neat cement is held in silos or P-Tanks in the same manner as bulk barite and bentonite.


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With an air pressure of 20 psi, cement powder is easily fluidised and flows readily. Excessive pressures should be avoided. Offshore tanks will often have a working pressure of 40 psi but this is higher than should be required. The bulk tanks should have a Pressure Relief Valve installed. This should be set slightly higher than the maximum working pressure – say 45 psi on a 40 psi WP tank. Periodic inspection and testing of these devices is required. When cement is pneumatically transferred over many feet (>30 ft) it can separate into slug flow. The surge tank situated close to the mixer smooths out the delivery and also allows for the switching of tanks when one becomes empty without interrupting mixing. Bulk systems on off-shore rigs are the responsibility of the rig contractor. Many rigs have been built and are still in service which have less than ideal bulk systems. Sometimes the tanks are remote from the unit and at a different level. Often there are considerable numbers of bends in the line. Not surprisingly, bulk delivery problems can be a major source of trouble for the cementer. Every effort should be made to identify causes of problems with the rig contractor and steps taken to resolve any short-comings.

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Off-shore bulk sysytems should always be equipped with driers on the compressed air supply. Moisture from ‘wet’ compressed air can adversely affect the properties of cement and render lab testing on pre-shipment samples erroneous. In any case, samples should always be taken from silos offshore and sent in to the lab for checking. It is not uncommon for cement to be within the API/ISO Specification when it is put on the boat and out of specification when it has been on the rig for a few days. Needless to say, boat bulk systems are a further source of problems with cement quality – not least due to contamination of tanks with other materials. Always ensure transfer lines and hoses are blown clean before a fresh delivery.

Cement Heads, Water Bushings, Sweges Cement heads vary depending on the number of plugs they will release and whether they have a facility to monitor release of the plug(s). Subsea release plugs obviously differ from surface plugs and liners require a different system. Sweges allow connection of smaller diameter pipe or lines to casing threads. They cross-over from casing to other pipe allowing fluids to be pumped down casing, perhaps to wash it to bottom. Their pressure rating should be greater than the casing to which they are attached; usually the larger, surface casing sizes


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The above head is a single plug cement head and manifold. If used with both a top and bottom plug, the bottom plug is loaded before the head is made up to the casing. The plug is released ahead of the cement and then, after pumping the rest of the cement into the casing, the head is opened and the top plug loaded. At this time the cement is most likely free-falling in the casing and there will be a rush of air as the head is opened. Alternatively, the bottom plug released and the spacer pumped, The head is then opened and the top plug loaded before pumping the cement. After pumping the cement the top plug is then released. The right hand manifold is for a two plug head allows both plugs to be loaded and circulation can be more or less continuous. Both heads have similar release mechanisms for the plugs – often a pin horizontally screwed into the body of the head. Two plug heads are sometimes too long for the standard bails on smaller rigs and there are always fears of releasing both plugs before the cement with obvious consequences. Rev. 01/2002


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Liner Cement Heads are similar in principle but hold the darts which are pumped down the drill pipe running string. They are, therefore, much smaller diameter. A sub-sea cement head consists of an assembly holding the plugs within the casing at seabed. These plugs are launched by darts or balls released from a head on the surface (similar to the liner head).


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Cement heads need frequent inspection for damage and for wall thickness. They also require periodic pressure testing. Details of the last pressure test and general inspection details should travel with the head to location. The following are the normal steps are required before use on a job.

• • • •

Clean all threads and check them with thread gauge Remove and clean all caps, and check all O-rings. Apply grease to all valves and make sure that they function correctly. Operate the plug drop pin or bail assembly to make sure that it functions properly.

• Check the bolts that hold the release pin or bail assembly to the head and make sure they are tight.

• Make sure there is a thread protector installed. • There should be additional O-rings for the cap, connector and pin in a container with the pressure test chart. Minimum Pressure Test Requirement for Cement Heads: In addition to the above inspection requirements, all cement heads must be pressure tested every 90 days to their component rated working pressure. Fasten a copy of the test chart to the cement head. Cement heads and their manifolds must have the normal annual inspections.

Float Shoes and Collars Float shoes and float collars are essentially non-return valves installed at the deep end of the casing string so that when cement is displaced into the annulus it does not flow back into the casing. If there was no such valve installed, the cement would U-tube back into the casing until the columns of fluid inside and outside were balanced. In fact, if a float fails to work, then pressure has to be held on the casing until the cement has ‘gone-off’ sufficiently to be self supporting. This is likely to introduce an undesirable micro-annulus due to ballooning of the casing. It is common practice to install a Float Shoe – which is a valve in a cementing shoe and a float collar. The collar is installed one or two joints above the shoe and may also be the landing collar for the cement plugs. If one float valve fails, the other may hold. Rev. 01/2002


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Obviously, these valves have to be able to cope with the erosion caused by mud and cement during pumping. In deep, hot wells (which often have high density abrasive muds) this can be a servere materials challenge. Some years ago the API introduced a test method to provide assurance on such equipment - RP 10F , Performance of Cementing Float Equipment , 2nd Edition, November 1995. The term ‘float’ comes from the use of the valve to enable the casing to be floated into the well. Obviously, with a check valve in place the casing does not fill up with mud as it is run and the weight carried by the derrick is reduced. This can assist some rigs to run casing strings they would otherwise be unable to.

Figure 6: A Flapper Valve Figure 7: A ball & cage valve


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Figure 8: A poppet type valve

If the casing is not manually filled at surface, at some stage – depending on the casing grade and mud weight – it will collapse. Casing is usually filled every 5 to 10 joints with a hose at surface to prevent this. Another type of float valve is called an auto-fill float shoe or collar. This auto-fill device is like a normal valve except that during running in the casing the valve is held open. The casing then fills with mud as it is run in and pressure surges associated with movement of the pipe are reduced. When casing is close to bottom the valve is ‘tripped’ or converted to a conventional one-way valve. Depending on the design, this may be done by dropping a ball or by exceeding a certain flow rate.

Stage Tools Stage equipment, either a stage collar or port collar, is placed within the casing string to provide a selectable intermediate passage to the annulus. Stage equipment is generally used to protect weak formations from excessive hydrostatic pressure, to cement two widely separated zones, and to reduce mud contamination. Stage collars are typically hydraulically opened and closed using free-fall darts and pumpdown plugs to select and shift the appropriate internal sleeve.The lower sleeve covers the ports initially. Rev. 01/2002


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Once the first stage is complete, the lower sleeve is pumped down to uncover the ports by seating the free-fall (or pumpdown) opening plug and applying pressure. The second stage is pumped and the ports are closed again by seating and applying pressure to the larger closing plug. Once closed, the stage collar cannot be reopened. The pressure required to open and close varies with manufacturers, but is generally between 800 and 1,400 psi. When two stagecollars are used, a special upper stage collar is required, and care should be taken to release the correct plugs in the proper sequence. The internal diameter of the upper stage collar seats must be larger than the lower collar seats. For highly deviated holes, the free-fall dart should be re-placed with a pumpdown plug. Figure 9: Stage Tool Operation


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Figure 10: Stage Collar Operation Port collars are mechanically operated from the surface with a tool connected to an inner string of drillpipe – see below. They are available with sliding or rotational valve mechanisms, and may be opened or closed as often as necessary. The sliding valves are generally opened with an upward motion and closed with a downward motion, and require a minimum of 10,000 lb to stroke. Port collars may be placed as often as necessary in the casing string and selected in any sequence. There are no plugs to use, nor drillout required. Some shifting tools may be fitted with cup type seals to form a conduit from the inner string to the ports.

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Figure 11: Port Collar Operation


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Casing Centralization Centralization Casing should be centralized for three main reasons: • To help get casing to bottom (this includes reduction of the potential for sticking) • To help move the pipe during hole conditioning and the cement job Provide a good path for fluid flow during hole conditioning and cementing (mud removal, zone isolation). Field experiences, numerous large scale experiments and computer simulations have all shown that even a slight de-centralization can be detrimental to the cement job, particularly in narrow annuli (for example SPE 8253, R. Haut, 1979). Therefore, a good centralization program should aim for high levels of standoff (90 - 95+%), particularly in critical wells and in production zones.

Reduce the Risk of Sticking the Casing Overbalance drilling across permeable formations generates mud cake and partially dehydrated-gelled (PDG) mud films across the permeability. In some cases, if the pipe is not centralized, it is possible that as much as 1/4 of the pipe surface area can be in contact with the mud cake and PDG films. This can lead to stuck pipe. Centralized pipe may only contact the mud cake in highly localised spots. The following simple example illustrates how centralizers can assist in reducing the potential for differentially sticking of the pipe. Assume 1,000 ft of 5” 18 ppf liner to be run across a permeable open hole. Assume a pressure differential (hole to formation) of 500 psi. Let’s assume that the formation consists of 10% sand and 90% shale

Casing Centralization 2-25 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Case on non-centralized pipe: Calculate the force needed to pull the liner if it gets stuck across the entire open hole. Assume that the pipe is contacting the cake along a 2” strip, the entire length of the pipe. Use a friction coefficient of 0.25 F = DP x Ac x Cf F = Drag force, lb DP = Differential pressure, psi Ac = Contact area, (sq. in) Cf = coefficient of friction (dimensionless) F = 500 x (1000 x 12 x 2 x 0.1) x 0.25 F = 300,000 lb Total Force needed: Liner weight + Drag Forces TF = 1,000 x 18 + 300,000 TF = 318,000 lb Calculate now what would the force be if the formation was 50% sand? F = 500 x (1000 x 12 x 2 x 0.5) x 0.25 = 1,500,000 lb!!! Case of casing centralized: Assume two centralizers/joint to keep the casing from contacting the formation. In this case, the added drag due to the centralizers is due the running force of the centralizers. Number of casing joints: 1000/40 = 25 Number of centralizers: 2 x 25 = 50 Starting force per centralizer for a 5” pipe ~ 520 lb Drag Force = 50 x 520 = 26,000 lb Total Force needed: Liner weight + Drag Forces TF = 18,000 + 26,000 = 44,000 lb. Notice that this force is only ~ 14% of the force needed in the differential sticking case! Conclusion: centralizers can reduce the chances of sticking the pipe! Rev. 01/2002


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Non Centralization Equals Poor Isolation Below are examples of large scale experiments run with centralized and non-centralized pipe. The arrows point to the mud channels in the non-centralized case.


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Channeling can also be predicted from rigorous fluid dynamics calculations using computer simulators of non-Newtonian flow. Below is a simulation of channeling of a Bingham Plastic fluid in an eccentric annulus. Notice how the fluid moves higher in the wide section of the annulus.

Less sophisticated computation can estimate the movement of fluids in variable eccentricity annuli (eccentricity varying up and down the annuls). An example of a non-centralized, long annulus is given in the attached graph. In the graph, the left side represents the wide section of the Rev. 01/2002


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non-centralized annulus. The right side represents the narrow section of the annulus. Notice that much mud (a large mud channel) was left on the narrow side of the hole. Positions of fluids in annular segments in wellbore at 180mins wide side 1

narrow side 2

3

4

0 2000 4000

depths (ft)

6000 Tail Slurry

8000

Lead slurry

10000

W.B. Spacer O.B. Spacer

12000

Mud

14000 16000 18000 20000

Figure 12: Pipe Movement Large scale experiments and controlled field trials have shown that good quality mud in the hole and proper hole conditioning prior to the cement job, are the keys to the success - assuming good centralization of the pipe. Full mobilization of the mud (full circulation) needs to be obtained before the start of the cement job. Experiments have also shown that pipe movement is beneficial. The extent of the benefit has been measured to be around ±10% without the use of casing jewelry. The way to obtain the full benefit of moving pipe is in combination with the use of high quality cable loop scratchers. The photo below (from a large scale experiment) shows the dramatic difference between pipe movement with, and without, cable loop scratchers.


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The sections of hole showing little to no dehydrated mud ring around the cement across the sand were scratched (pipe movement). The others had no scratchers (same cement job).

How is Centralization Achieved? Centralization is achieved using mechanical devices which push casing away from the formation wall. Key factors are:

• The tools have to provide enough load-support to overcome the normal • •

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forces tending to lay the casing against the formation, particularly in deviated holes. Enough tools need to be used to provide casing “centralization” over the needed intervals. It is normally assumed (however not always the case) that the formation can provide enough support for the tools (minimum embedment)


Cement Manual

Centralizer Types Available The industry has developed three main types of centralizer:

• Bow • Rigid • Solid Bow Spring Type: The bow type consists of flexible, heat-treated steel spring bows attached to two collars. By design, the bows are flexible enough to allow passage of the centralizer through restrictions, but are also provide sufficient stand-off in enlarged hole areas. The springs come in various shapes and dimensions. The relaxed OD of the bows is normally larger than the nominal hole (bit) diameter; thus affording potential centralization in moderately washout zones. Double bow (tandem) centralizers are also available. They provide excellent restoring forces with low starting and running forces.

Figure 13: Example of Bow Spring Centralizer


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Figure 14: Example of Double Bow Spring Centralizer Rigid type: Rigid centralizers are made out of non-flexible fins attached to collars. The fins are not designed to flex and therefore maintain a constant OD. The centralizers possess very little flexibility. These devices only adjust to slight hole restrictions or enlargements. Several types of rigid centralizers are available. Good examples of these devices are Weatherford's SpiraGlider and the STT-I-SL Slim Line centralizer,often used for liner centralization.

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Figure 15: SpiraGlider

Figure 16: Slim Hole Centralizer


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Solid Type: Solid centralizers are manufactured with totally non-flexible fins or bands. These centralizers have solid bodies and solid blades with constant blade OD. They have zero flexibility and therefore cannot adjust to any hole restriction or enlargement. Good examples of this type of centralizer are the Spir–O-Lizer and the aluminum spiral centralizers manufactured by Ray Oil Tools, Weatherford and others.

Figure 17: Spir–O-Lizer

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Figure 18: Aluminum Spirals


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Some Important Advantages/Disadvantages Bow Spring Advantages

Disadvantages

Can adjust to varying hole sizes (can potentially maintain stand-off even in irregular hole size)

Due to the spring bows, these centralizers exhibit high starting and running forces.

Some designs incorporate fins to induce swirl over a limited length which can assist mud removal and isolation

Some designs are very strong, but others are weak and fall apart while running in the hole (a source of many stories of unsatisfactory performance)

Relatively low cost

In highly deviated/horizontal holes, improper use of these devices can prevent casing from getting to bottom,

Advantages

Disadvantages

Good where clearance is limited and hole is close to gauge.

Fixed OD. Exhibit little flexibility. Not capable of adjusting to varying (large) hole sizes.

Some deformation of the fins helps to run the centralizer through hole restrictions

No action in washout areas or over-gauge hole.

Rigid

Some designs have good flow path characteristics, i.e.low restriction to flow (SpiraGlider).

Solid Advantages

Disadvantages

Positive stand-off in gauge hole

Fixed OD. No flexibility. Incapable of adjusting to varying (large) hole sizes.

Robust – can stand rough handling and high downhole forces.

No action in washout areas or over-gauge hole. The designs do not allow for deformation to help run the centralizer through hole restrictions. If the centralizer gets stuck, the only way to get it to go through is to break the centralizer or for the stop rings to slip (forming a centralizers “nest”) The design presents the highest flow restriction of the three types. Consequently, care needs to be exercised when using them in narrow annuli (slim holes, etc.).

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How Much Cement is Needed for Isolation? A few feet of well bonded cement (to pipe and formation) may be all that is needed to isolation a zone. However, we normally want better protection than that for the life of the well. We try to isolate above, across and below critical zones and productive horizons. We also need to properly protect and support the pipe for the life of the well (corrosion, formation movement, etc.). Thus, normally, we need to design and attempt to obtain good cement jobs across long intervals. Washouts and hole ovality are a problem and they are normally not confined only to shales. It is not uncommon to find them across sands and pay. Centralization in elliptical, deviated hole is a real challenge. The Balancing Act Particularly in deviated (ERD) and horizontal wells, it becomes necessary to optimize between good centralization (high standoff ratio) and low drag forces. The problem is not just good centralization but also being able to run the string to TD. These applications require the use of computer simulators to calculate the normal, drag and torque forces based on well trajectory, mud type and density, and the centralizer properties. This will allow optimization of the centralization selection, placement and numbers. Good centralization (high stand off ratios) calls for centralizers with high restoring forces (like the bow spring type). Low drag forces require centralizers with low starting and running forces (like the rigid and solid type). Rigid and solid centralizers have lower running forces than bow spring centralizers, but their fixed OD renders them incapable of responding to hole size variations. In addition, the drift of the previous casing often limits the OD of the centralizer that can be run. The size (OD) of the rigid, or solid, centralizer in a given case can be too small to generate the desired degree of stand-off for good cementation. This becomes even more severe in cases where the open hole has been under-reamed or has washouts or ovality. Let's look at a simple example. We will examine only standoff at the centralizer. The standoff ratio that we really need to be concerned about is at the sag point of the casing, but that requires the use of a simulator. Standoff at the casing sag point is lower than the standoff at the centralizer.


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Calculating standoff for a rigid or solid centralizer (at the centralizer): W = Rc - Rp (assumes the centralizer blades are contacting the hole wall)

• Rc = radius of solid/rigid centralizer • Rp = outside radius of the casing • Rb = radius of the borehole % standoff = W/(Rb - Rp) x 100 (assumes the centralizer is contacting the wall) By the way, notice that by definition (as per the previous equation) it is impossible to obtain 100% standoff with rigid or solid centralizers since the maximum OD of this type centralizers is always less than the OD of the hole!. Example: Previous casing: 9-5/8 in, 43.5 lb/ft, drift diameter: 8.599 in. Open hole (bit size) 8.5 in. Casing to be centralized in the open hole: 7 in. Max. OD of rigid or solid centralizer that can be safely run inside the previous casing: 8.599 - 1/8 in = 8.474 in. Recommended (available) solid or rigid centralizer OD (from manufacturer's tables) for an 8-1/2 in. hole: 8.25 in. % standoff = ((8.25 - 7)/2)/((8.5 - 7)/2) x 100 = 83 % This is the best standoff that can be obtained with this type centralizer!. It of course assumes that the hole is equal to the bit size (normally not the case). If we now assume a more realistic situation and visualize the hole being larger (the entire hole or sections of the hole) than the bit size, then we can see the real problem with fixed OD centralizers:

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Hole OD (in.)

Stand-off

8.50

83

8.75

71

9.00

0.63

9.25

0.56

10 (washout)

0.42


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Even the best obtainable standoff of 83% (hole size = to bit size) may not be good enough to get a decent cement job!. For critical situations we want to design for 90 - 95 % standoff. Normally rigid and solid centralizes cannot give us that level of standoff in real holes. We need to also remember that normally the centralizers are purchased and often installed way before the size of the open hole is known (caliper). On the other hand, bow spring centralizers for this example can have max. OD's of over 13 in., with a compressed OD of as low as 8.231 in.(less than the previous casing drift diameter). Bow spring centralizers can potentially provide the desired high levels of standoff, as long as the normal forces are not excessive (see below). So, the main advantage of bow spring centralizers is that due to their flexibility, they present the best chance of properly centralizing the pipe (the issue of the quality and durability of bow spring centralizers will be visited later on in this document.)

The Benefit of Swirl (Spiral Flow) Swirl can be beneficial to the displacement process. It can move cement from the narrow side to the wide side to at least increase the chance of intermittant isolation. However, the danger lies in thinking that spiral flow is a solution to the problem and sacrificing standoff (by not using bow spring centralizers). Experiments to measure the angle and length of the swirl of different swirl inducing devices have been conduced by the industry. The bulk of the studies have been performed in pipe, with no permeability (for example, the JIP at Southwest Research Institute in San Antonio, USA in 1991). These experiments showed a rapid initial decrease in swirl downstream of the aid, which decayed at a slower rate as the distance increased. The effects of higher swirl angles have always been concentrated in the proximity of the devices. This behavior is observed even at high rates (Reynolds Numbers). Therefore, it is very doubtful that the potential benefit of the use of swirl inducing devices can be experienced at locations other than at or very close to the device; regardless of the type of fluid or the pump rates used.


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An example test is shown below. Notice the high angles concentrated very close to the device. Experiments and mathematical simulations have also shown that even minor hole enlargements and eccentricity significantly reduce the beneficial effects produced by the swirl due to portions of the flow bypassing the device and not turning (Wells, 1991).

Based on these and other experiments, some in the industry have concluded that the fact that the flow turns around the pipe, that that means that the cement will always end up covering the entire annulus. Unfortunately, this is not always the case in real holes. Very few experiments have been conducted under realistic downhole conditions, including the presence of permeability and hole inclination. Permeability has a dramatic effect on the mobility of mud films and solids laden beds on the low side of inclined holes. Due to partial dehydration and gelation, mud films across permeability often exhibit levels or resistance orders of magnitude greater than non-dehydrated mud portions (this depends also on the mud properties. Oil base type muds for example, generate the most mobile mud films). To remove the partially dehydrated-gelled mud films, spacer fluids have to be designed with rheologies high enough to be able to apply the needed levels of stress. Rev. 01/2002


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Thin fluids often cannot generate the necessary stress at the fluid-mud-film interface. Mud films around the cement, across the permeable sand can be seen in the first photo above. Below is another example.

Figure 19: Turbulator in a deviated, enlarged section of hole This photo shows a turbulator in an enlarged hole across permeability. Notice the presence of unremoved dehydrated gelled mud across the permeability, and a bed of solids on the low side of the hole. Turbulators were also tested in permeable, non-enlarged, inclined holes (small clearance between the blades and the hole), and as expected, they did a better job of helping remove the mud than across washouts. In the very near proximity of the turbulators, less settled solids and partially dehydrated-gelled mud films were observed than away from the device, but the device did not completely clean the annulus, even right where the tool was located. The photo below is not very clear but it illustrates the point. Notice the bed of solids on the low side of the hole, right at the centralizer.


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Figure 20: Turbulator across Permeability in an Inclined Hole So, swirl by itself does not completely remove the dehydrated-gelled films of mud and solids beds in the hole. Why? Mobility of partially dehydrated-gelled mud film has been measured in large scale experiments. As mentioned, the mobility of those films can be orders of magnitude lower than the non-dehydrated mud. The film is removed if the flowing fluid applies sufficient interfacial shear stress higher than the resistance of the film. That the fluid turns with swirl inducing devices does not mean that the needed stress is applied. Much of the energy needed to remove the film is lost with the fluid that bypasses the on the wide part of the hole. So, Swirl Inducing Devices (rigid or solid) do not solve the problem, and they do not provide enough standoff. Bow spring centralizers have also being found to improved mud cleaning in the very near proximity of the devices. Crook performed experiments in pipes in 1985. He showed that bow spring centralizers improve displacement in inclined holes, particularly near the centralizers (SPE 14198, Crook, 1985). Also, remember that bow spring centralizers can be purchased with fins to further induce flow disturbances at the device. Anything which disturbs flow is likely to help but over a short length.

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Figure 21: Effect of Bow Spring Centralizers in the Proximity of the Device (after Crook, 1985) Spiral Centralizers Digging (Plowing) into the Hole There are documented field cases pointing to this possibility, particularly in short radius holes and/or across "soft" formations. Cuttings beds, of course, offer a real problem if they are pushed ahead. Therefore, caution needs to be exercised when using high angle blade centralizers. In an experimental well, a 7" casing with 45 degree blade angle turbulators was run in a 9-7/8" hole with a 90 degree dog leg over 463 ft (from 0 to 90 degrees) with a 125 ft lateral. The well was drilled across hard rock. With the turbulators, the casing could not be run to bottom. After pulling the casing out of the hole, packing-off was observed around the turbulator blades. Straight solid centralizers (aluminum) were run next. Difficulties were again encountered, and the pipe was again pulled out of the hole. One centralizer was never recovered; another was cracked. No packing-off was noticed across the centralizers. A reaming run was made, and the casing went down this time, with some difficulty. In a field case, packing-off problems have been reported while circulating with high angle blades centralizers. Plowing was suspected in this case when the hole began packing-off while washing down the liner. The problem was cleared by picking up the string and circulating.


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Quality of Bow Spring Centralizers Concerns regarding quality and durability of bow spring centralizers are definitively justified. Some manufactures have marketed and still do, devices that should never be run in the hole. They are junk! Unfortunately, these poor quality devices have caused many users to be very skeptical and doubtful of the performance of bow spring centralizers in general. Another problem is that the entire topic of stop collars, for some unknown reason, has been neglected by many operators, and therefore not enough pressure has been applied to manufacturers to produce and collars the can be used to keep centralizers in place. It is not uncommon to find operators concerned about the type, size, etc, of the centralizers to be used, but leaving the issue of stop collars completely unaddresed. Frequently, centralizers are no longer installed by trained service company personnel. Torque wrenches are not used in the installations, etc. Many centralizers that fail downhole become damaged because the collars allow them to move and end up bunched up across hole restrictions. Fortunately, there are available in the industry, high quality bow spring centralizers. That has been shown during industry testing, for example by Amoco in 1992 and recently by BP (2000). During the Amoco study, destructive, non-API tests were conducted on bow spring centralizers from six different manufacturers. These tests were performed in addition to the API tests required by Spec-10D. The centralizers were placed under tension with a force of up to 50,000 lbs. In addition, they were tested under compression and impact loading by dropping a load of 1,900 lbs from a distance of 9 inches up to 30 times onto the top centralizer collar. Needless to say, many of the centralizers failed. However, two designs held up very well: the old Gemoco (now made by Weatherford) and the old Halliburton construction. The designs that performed well were all welded. So, When Should We Use Rigid and/or Solid Centralizers? Bow spring type centralizers should always be the first choice, except when high quality bow centralizers will not perform due to large normal and/or running forces, such as highly-deviated/horizontal, high dogleg applications. This needs to be determined using a good simulator like Weatherford's CentraPro. Torque forces and drag need to be calculated as well as the standoff. The figures below are simulator generated. The first one shows a case where the pipe could clearly not be run to bottom due to the high drag generated by the bow spring centralizers. The next figure shows that a rigid type centralizer would allow the pipe to get to bottom. The centralizer of choice to run in this case is obvious. Rev. 01/2002


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Example: Casing size: 7 in, 23 lb/ft Hole: 8-1/2 in. Mud: 10 lb/gal Horizontal hole section: 6000 ft Legend for the following figures: Upper Line: upstroke hookload, Central Line: neutral weight, Lower Line: downstroke hookload

Figure 22: Bow Spring Centralizer Case:


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Figure 23: SpiraGlider Case: Calculated excessive normal forces (forces that tend to flatten the centralizer) can force the selection of the centralizer to move toward rigid or solid from bow spring. The figure below illustrates this situation. Notice that after certain point, the rigid or solid selection is again obvious due to excessive normal forces that can be generated across for example severe doglegs.

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Durability and Wear Published and field data tell us that friction coefficients in drilling operations are dependent mainly on the drilling mud and its additives (lubricants), so, not much is really gained by using centralizers made out of "soft" materials. Actually, much could be lost due to wear! The data below shows that the material of choice needs to be steel over aluminum and other materials such as aluminum-zinc alloys. Steel resists wear much better than the other materials, providing a better change for the centralizer to get to bottom without much wear (preservation of standoff). The wear factors shown below were obtained in the laboratory using the pin-on-disk technique. The test conditions are given first.

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Wear in Microns Specimens Disk Material Steel

Aluminum-Zinc

Aluminum

Steel

4.5

31

135

Sandstone

7.8

45.4

357

Stop Collars – the neglected issue Considering the complex issue of casing centralization, stop collars and their holding capacity are the most neglected aspects of the entire topic. Stop collars are extremely important to the successful centralization. If the collars are damaged or if they move, even the lowering of the casing in the hole can be jeopardized. Centralizers become junk in the hole! When hole conditions allow, centralizers are sometimes placed over casing collars. This eliminates the stop collar concerns. On the other hand, this technique is not a good one for casing reciprocation (it is not desirable to have the centralizer move with the pipe), cannot be used in tight annuli, and it tends to concentrate the normal forces on the casing connections. Different hole configurations require different collar designs, but they all have to provide substantial holding force. Since the forces that the collar will see downhole cannot be reliably predicted, the answer to the question how much force do we need is: as much as we can get! Experiments have been conducted comparing the holding forces of different collar types. Large differences have been reported among the different designs. Below is the result of tests conducted back in 1992. Collars with screws and "dogs" gave the greatest holding force. Tests have also been conducted adding "Baker Lok" type materials in between the collar and the pipe. Those tests have indicated that you can substantially increase the holding force of a given collar that way (by as much as 5). Stop collars also need to re-tested. The API Spec-10D provides a method to test the holding and slippage forces of stop collars. Depth of the gouge on the casing after the collar moves should also be measured. The tests should be conducted using the same grades of pipe to be used in the actual wells. Casing Centralization 2-49 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Section 3: Cement Cement Aims: • Cement - what is it and how does it work? • Manufacture • Limitations • Modifications to make it suitable for use under different well conditions - particularly temperature and pressure.

What is Cement? Clays and lime (CaO) were used as binding materials for stones from early times. The Romans used materials of volcanic origin (natural pozzolans) and found that pozzolans with lime produced a competent cementitious material that could be used in building. A crude lime mortar was used in the building of the pyramids. In 1756 John Smeaton rebuilt the Eddystone Lighthouse using a mixture of natural pozzolan and lime. Modern Portland cements started with the calcination of limestones - heating CaCO3 - to produce quicklime (CaO). Later it was found that impure limestones containing clay produced mortars that worked better than the more pure limestones. These findings led to the burning of blends of limestone (calcareous material) with silica and clay (argillaceous) materials. In 1796 James Parker produced a material he called ‘Roman’ Cement; one of the first cements that set and and remained water resistant. It was used in Brunel’s Thames Tunnel and in railway bridges built by Robert Stevenson.

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

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Joseph Aspdin, who had a factory in Wakefield in England, was granted a patent by the British Government in 1824 for a cement he had developed. Aspdin called his cement Portland cement, because concrete produced from it resembled stone quarried on the Isle of Portland off the south coast of England. He claimed “it is not subject to atmospheric influences, and will not, like other cements, vegetate, oxydate, or turn green but will retain its original colour of Portland stone in all seasons and climates”. Portland cement was first produced in bottle kilns and then in shaft kilns. It was an American, Frederick Ransome who produced the first modern rotary kiln in 1885. Portland cement was first used in oil wells around 1903 to shut-off water. By 1917, Portland cements were used routinely in cementing of hydrocarbon wells. As wells became deeper, hotter and more difficult to cement, the industry required the manufacturers to modify the properties to produce ‘so called’ oil-well cements. Most cement is, of course, produced for the construction industry and relatively little for the oil industry. The properties required differ considerably. The American Petroleum Institute (API) established the first committee to study oil well cements in 1937. Specifications for different oil well cements followed and the industry developed ways to modify properties with additives to enable them to perform under demanding well conditions.

Manufacture of Portland Cement The principal compounds used to manufacture Portland cement are calcium oxide, silica, iron, and alumina. The raw materials providing these compounds are normally calcium carbonate (limestone), clay, shales, iron ore, and aluminum ores. The calcium carbonate can be obtained from limestone, oyster shells, chalk or marl. This material is reduced to calcium oxide during the manufacturing process. Silica is obtained from clay, shale, or other sources of silica. Iron and alumina are added in varying quantities to control the composition of the final product. The raw materials are ground and combined by one of two processes: dry or wet. Rev. 01/2002


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The dry process consists of crushing the materials separately, storing each in bins, performing chemical analysis on each and then blending prior to being ground to a fine powder. The final blend is analyzed, adjusted as needed, and fed to a rotary kiln. In the wet process, the limestone is crushed and stored. The clays and shales are crushed and mixed in water flotation tanks to remove unwanted impurities and large chunks. The dry materials are then mixed into this dispersion to form a slurry. The slurry is analyzed for correct chemical content. Then the slurry is fed into a wet grinding mill, analyzed again and fed into the rotary kiln. The normal concentration of material in either system is approximately two parts limestone to one part clay and shale with small amounts of iron and alumina.

Figure 1: Cement Manufacturing Process As the particles migrate down through the kiln and are heated, several reactions take place. First the free water or moisture is driven out. Then the clays and shales are reduced to silica and alumina. Further heating drives off carbon dioxide from the limestone reducing it to calcium oxide. These compounds are Cement 3-3 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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further heated to temperatures of 2,600 deg F, 1400 deg C. At these temperatures the new cement compounds are formed. As the liquid material approaches the lower end of the kiln, the various compounds fuse together forming chunks of material called clinker. Clinker varies in size from dust to about 2 inches in diameter. The clinker passes from the kiln into either a grate or rotary cooler where it is cooled in air. After a period of storage, it is ground in a ball mill with gypsum to form the final cement. Gypsum, in 1.5 to 3.0 percent by weight of cement, is used to control the rate of setting and hardening of the cement. The materials are ground to a specific fineness, dependent on the type cement desired, and the end product is stored in bins for shipment. This is the final grey powder material commonly known as Portland cement. Figure 2: Portland Cement Burning Temperature Ranges 100 Deg C:

Evaporation of Free Water

500 Deg C:

Dehydroxylation of Clay Minerals

900 Deg C:

Crystallization of Products of Clay Mineral Dehydroxylation Decomposition of CACO3,

900 - 1200 Deg C:

Reaction Between CACO3 or CaO with Aluminosilicates.

1250 - 1280 Deg C:

Beginning of Liquid Formation

1400 deg C:

Further Liquid Formation and Formation of Cementitious Compounds

Chemistry of Portland Cements Four chemical compounds form about 95% of the cement clinker by weight. These materials have a major impact on the strength developed of the set cement. Minor concentrations of gypsum, sodium and potassium sulfate (Na2SO4 and K2SO4), magnesia (Mg), free lime (CaO) and other admixtures are also present in cement. Normally these minor components do not significantly affect the properties of the hydrated cement. However, they do influence the rate of hydration, resistance to sulfate attack and they also impact the properties of oil well cement slurries. Rev. 01/2002


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Phase

Chemical Nomenclature

Percentage

Tricalcium silicate (called alite)

C 3S

65%

Dicalcium silicate (called belite)

C 2S

17%

Tetracalcium aluminoferrite

C4AF

14%

Tricalcium aluminate

C 3A

2%

In this nomenclature, C=CaO, S=SiO2 , A=Al2O3 , F=Fe2O3, H=H2O, etc

Tricalcium Silicate (C3S). Forms from CaO and SiO2. During hydration, two molecules of C3S generate three molecules of lime. Normally the lime acts as a filler and does not negatively affect the cement. However, in the presence of acidic well fluids, it can contribute to cement deterioration. At elevated temperatures (above 230F), the lime can react with finely divided silica added to the cement slurry to form stable calcium silicates, which contributes to the integrity of the cement. C3S is the major compound in most cements. It constitutes 40 to 45% of normal cements. In high strength cements it can be as much as 60 to 65% of the total composition. C3S is the main strength producing material. It contributes to all the stages of strength development, but particularly during the early stages. (up to 28 days). Dicalcium Silicate (C2S). It is also formed from the reaction of CaO and SiO2. This component hydrates slowly, so it does not affect the initial setting of the cement. However, it has a great impact on the final strength development. Dicalcium Silicate is the slow hydrating compound and accounts for the small, gradual gain in strength which occurs over extended periods of time. Tricalcium Aluminate (C3A). This compound if generated by the combination of CaO and Al2O3. C3A does not contribute greatly to the final strength of the set cement. However, it is the compound that responds most actively to cement additives and promotes rapid hydration (early strength development) and it is the component that controls the initial set and thickening time of the cement. The set time of C3A can be controlled by the addition of gypsum.


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Tricalcium Aluminate is responsible for the cement susceptibility sulfate attack. The final hydrated products from C3A are readily attacked by sulfate waters. Therefore, to be classified as a high sulfate resistant (HSR) cement, it must have three percent or less Tricalcium aluminate. On the other hand, high early strength cements can contain up to 15% C3A. Figure 3: Illustration of the Main Cement Compounds

Cement Hydration or 'How does it Work?' The chemistry of the hydration of cements is not exactly known, and is still the subject of controversy. It is, without doubt, very complex. One of the keys to understanding lies in Calorimetric studies made from first mixing of cement with water. These show two distinct peaks in the rate of heat liberation. The first peak lasts only a few minutes and for an oil well cement corresponds to the time the slurry is on surface. Many reactions are occuring; the important ones being the formation of a gel coating on the grains (CSH gel) and a calcium trisulphoaluminate hydrate known as Ettringite.

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Figure 4: Hydration of Cement: Calorimetry - Heat evolution with time

Figure 5: Hydration of Cement: Calorimetry – Effect of temperature Following this initial exothermic reaction, there is then a period, which may last from 30 minutes to several hours, when little or no heat is liberated. The cement slurry remains liquid and behaves as if hydration had stopped. This is known as the 'induction period' and is one of the reasons for the success of Portland cement since it allows concrete to be placed in position. It also, of course, allows oil well cement to be pumped into place without continuously increasing viscosity.


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According to one hydration theory, the CSH gel layer acts as a semi-permeable membrane which allows water molecules to diffuse into the grain but slows down calcium and hydroxide ion migration into solution. Therefore, osmotic pressure continuously builds during the dormant period until a critical stage is reached and the CSH gel layer ruptures. This heralds the onset of setting. The rupturing is accompanied by growths of ‘spikes’ from the grains and the locking together of these spikes causes viscosity increase and then strength to develop. Grains of API class G cement well into the hydration process. Hydration Products

Anhydrous Clinker

Fast C-S-H gel

C3S

(Colloidal – Variable Composition)

C2S

Slow C3A

Ca (OH)2 Portlandite (Crystalline)

Fast but retarded by Gypsum Sulpho-ferriAluminate hydrates

C4AF

Gypsum

Figure 6: Cement Reactions: the size of each box represents the approximate volume of each phase

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After the paste has gained strength, the reactions become diffusion controlled. At this time a local reaction product of dense fibrous C-S-H hydrate is formed. This 'late' or 'inner' product accounts for the high strength and low permeability of the set cement structure. The above brief synopsis of the setting process emphasized the hydration of the C3S phase, for the simple reason that it is judged to be the main factor involved in cement setting and hardening. The slower reacting C2S is probably responsible for the long term hardening process and may follow an essentially similar hydration mechanism. The aluminates, though important in the early stages, are largely halted in their reaction by the presence of available sulfates; and their contribution to the final strength is minimal. Since the volume of the hydration products is more than double that of the cement powder the spaces between the original grains of cement are gradually, but not completely, filled. Once the cement slurry has set solid, hydration continues but rarely will all the cement be hydrated. A set cement can have a quite high porosity (30%) althought the permeability can be very low (similar to a shale). It is the degree of porosity – together with the strength and structure of the hydration products – which governs the strength and other properties of the hardened cement. Porosity is dependent on the initial water/cement ratio – a lot of water will result in a high porosity and a low strength. Conversely, a low porosity hardened cement will have a high strength.

Limitations of Cement The performance of cements, particularly under elevated temperatures and pressures, will vary from cement plant to cement plant and from one manufacturer to another. This is due to variations in raw materials and in the actual manufacturing process. Other factors add further variability in the performance of cement slurries used in hydrocarbon producing wells. These slurries require chemical additives to modify the properties to accomplish cementation of the casing under widely different downhole conditions. The inclusion of additives brings more potential for discrepancies in the response of cement slurries, since the chemicals themselves are manufactured materials with their own potential for performance changes. Cement 3-9 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The extreme temperatures themselves magnify the effect of composition variations. It is well known that the rate of chemical reactions dramatically increases with temperature. The result is that to prevent cementing job failures, slurries need to be tested using the actual cement batch, field water and additives batches to be used in the actual job.

• Cement varies. • Water varies. • Additives vary.

Brief History of the Use of Cements in Oil Wells in the USA The U.S. petroleum industry goes back to the drilling of the Drake well in 1859. The first recorded use of cement to shut off downhole water was in 1903 in the Lompoc Field,

California. Frank Hill, with Union Oil Company, mixed and dump-bailed 50 sacks of neat Portland cement into the well. The procedure worked, and the treatment became the accepted practice and soon spread to other California fields. The dump-bailer technique was replaced by the two-plug method in California by A. A. Perkins in 1910. It was with Perkins' method that the modem oil well cementing process was born. The patent issued to Perkins specified two plugs. Before 1940, wells were cemented using construction sacked cement mixed by hand using very few additives. In the 1930's no additives were used. However, as wells became deeper, more flexibility in cement performance was required than could be achieved with available construction cements. The American Petroleum Institute (API) Committee on Oil Well Cements It was with the advent of the API Standardization Committee in 1937 that the search for better cements for wells started. The API Sub-Committee 10 is still in existence today and, in association with ISO, sets the current specifications for oil well cements.

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An API cement is a cement that meets performance and chemical specifications set by the API for the specific grade and class of cement. Today, there are eight API classes of cements each with distinctive characteristics and performance. Five of these API classes are commonly used today by the oil industry, and three used very little. The API Classes in common use are A, B, C, G, and H. API classes D, E, and F are not used in the U.S. and Canada and very little elsewhere. About 80% of the oil well cements used in the U.S. are Classes G and H. In international operations, most of the cement used is Class G. The detailed specifications of the eight API cements are given below, taken from: 'Specifications for Cements and Materials for Well Cementing, API Specification 10A, January, 1995.' The specific application for a given cement will depend on several factors including well location, downhole conditions and availability. API Cement Specifications (Classes and Grades) The American Petroleum Institute (API) sets specifications for the following cement classes: As well as the Classes A, B, C, D, E, F, G and H the API recognises grades of sulfate resistance: ordinary, moderate sulfate (MSR) and high sulfate resistance (HSR). Class A Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. This product is intended for use when special properties are not required. It is available only in ordinary (0) Grade (similar to ASTM C 150, Type 1). Cement 3-11 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Intended Application: This cement is intended for use from the surface down to about 6,000 feet, or to 170F bottom hole static temperature, when special properties are not required. Class A (ASTM Type 1) cement is manufactured using specifications applicable to the construction industry. The primary use in well cementing is for surface pipe, or other applications of low temperatures and pressure. Due to potential variations in the cement performance from mill to mill, slurries formulated with this cement need to be tested very carefully each time. Class B Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. This product is intended for use when conditions require moderate or high sulfate-resistance. Available in both moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades (similar to ASTM C 150, Type 11). Intended Application: This cement is intended for use from the surface to 6,000 feet, or to 170F BHST, where moderate or high sulfate resistance is required. This cement is manufactured according to more stringent specifications than Class A and is similar to ASTM Type II. Class B is similar to Class A, but it contains less C3A and is generally ground more coarsely. This causes longer thickening times and slower strength development than Class A. This cement is recommended for the same range of uses as Class A. Class C Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. This product is intended for use when conditions require high early strength. Available in ordinary (0), moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades (similar to ASTM C 150, Type 111). Rev. 01/2002


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Intended Application: This cement is also intended for use from the surface to 6,000 feet, or to 170F BHST, where conditions require high early strength or high sulfate resistance. It is a common misconception that Class C cement cannot be used at depths greater than 6000 feet. In fact, slurries using Class C cement have been designed and used successfully in West Texas and New Mexico at depths in excess of 10,000 feet. The lighter slurry density (14.8 ppg) of these cements sometimes gives Class C cement a distinct design advantage. Class C is available in ordinary, moderate (similar to ASTM Type 111) and high sulfate resistance types. Several manufacturers make Class C under different trade names. Through iron modification, all are produced free of C3A which is the cement constituent attacked by the sulfate ion and whose absence renders cement highly sulfate resistance. These cements are mainly used in West Texas and New Mexico. Other oil-field-related uses are for the lining of steel pipe that carry sulfate-bearing flood waters for secondary recovery. Class D Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. Further, at the option of the manufacturer, suitable set-modifying agents may be interground or blended during manufacture. This product is intended for use under conditions of moderately high temperatures and pressures. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades. Intended Application: Class D cement is intended for use from 6,000 to 10,000 feet, or from 170F to 230F BHST where moderate temperature and pressure conditions are present. This cement is classified as one of the manufactured slow-set cements and is no longer generally available. A "slow set" cement is defined as a cement in which the thickening time was extended by (1) eliminating the rapid hydrating components in its composition or (2) by adding a chemical retarder. Starch is commonly used as the retarder in Class D cements. Class D cement has been replaced by Class G and Class H cements for most applications. Cement 3-13 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Class E Specifications: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. Further, at the option of the manufacturer, suitable set-modifying-agents may be interground or blended during manufacture. This product is intended for use under conditions of high temperatures and pressures. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades. Intended Application: This cement is intended for use from 10,000 to 14,000 feet, or from 230F to 290 deg F BHST, where high temperature and pressure conditions are present. This cement is also classified as one of the manufactured slow-set cements and is not generally available. Lignosulfonate retarders are commonly used in the manufacture of Class E cements. Class E cement has been replaced by Class G and Class H cements. Class F Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. Further, at the option of the manufacturer, suitable set-modifying agents may be interground or blended during manufacture. This product is intended for use under conditions of extremely high temperatures and pressures. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades.

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Intended Application: Class F cement is intended for use from 10,000 to 16,000 feet, or from 230F to 320F BHST where extremely high temperature and pressure conditions are present. This cement is also classified as one of the manufactured slow-set cements and lignosulfonate retarders are used in its manufacture. Class F cement was used primarily in overseas markets but it has been largely replaced by Class G and Class H cements. Class G Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. No additions other than calcium sulfate or water, or both, shall be interground or blended with clinker during manufacture of Class G well cement. This product is intended for use as a basic well cement. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades. Intended Application: Intended for use as a neat cement from the surface to 8,000 feet, or to 200F BHST, without additives. When modified with additives, this cement can be used for most well applications both shallow and deep. This cement is manufactured under stringent requirements for chemical content and physical performance tests. Class H Specification: The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. No additions other than calcium sulfate or water, or both, shall be inter-ground or blended with the clinker during manufacture of Class H well cement. This product is intended for use as a basic well cement. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades. Intended Application: Intended for use as a net cement from the surface to 8,000 feet, or to 200F BHST, without additives. When modified with additives, this cement can also be used for most well applications both shallow and deep. Cement 3-15 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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More on Classes H and G: The API Class G basic cement was developed in 1964 and was specifically tailored for use in California. It was successful and the use of it spread to the Rocky Mountain area. This success led to the development of API Class H basic cement in 1967 and was designed for use in the Gulf Coast area where higher slurry densities were required. The purpose of the development of these two classes of cement was to provide basic (neat) cements without additives, which would not vary in composition among manufacturers. They would be standard products that could be interchanged in various slurries. Class G and Class H cements are both manufactured to the same chemical and physical requirements. The only difference is in the grind. Class H is ground more coarsely than Class G and, therefore, requires less mixing water, resulting in a higher slurry density. The water ratios for these cements are 38 percent for Class H and 44 percent for Class G. It should be noted that in many applications, Class H Cement is mixed at 46 percent water as though it was a Class A cement. This excess water can increase the thickening time, decrease the compressive strength development, and result in excess free water within the cement column. This practice requires that careful laboratory testing be performed with the cement and additives prior to the job to make sure that the slurry and set cement possess the required properties. Other Commonly Used Cementitious materials Pozzolans Pozzolans (poz) are the oldest truly cementitious material. It is known that the Romans used natural (volcanic ash) pozzolans as a binding product in their structures. Pozzolans normally do not possess cement-like properties of their own. However, when mixed with lime and water, they form compounds that do possess cementitious value. Since lime is found in Portland cements and it is also liberated during the setting of cements, if pozzolans are combined with Portland cements, the lime will react with the pozzolan. The pozzolan reaction depends on time and temperature. It occurs slowly at temperatures below 140F, and faster above that value. Straight poz and lime slurries (no cement) have been use at elevated temperatures. Rev. 01/2002


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It has been found that the addition of poz to cements is beneficial in reducing shrinkage, improving sulfate resistance, and in helping stabilize strength developments to temperatures near 270F. In addition, the inclusion of pozzolans reduce slurry density and cost. Cement slurries containing poz have other good characteristics such as good rheologies, usually easy to mix, have low heat of hydration (in situations like permafrost, high heat of hydration is not a desirable property), and can possess low permeability. Pozzolans slurries are good filler type slurries due to their relatively low densities and high yields, They can also be used as completion cements (across the pay). Artificial pozzolans are derived from the burning of coal and are called "fly ash". The oil industry uses fly ash almost exclusively over natural pozzolans. Variability of the material can cause difficulty in slurry design and so many of the advantages are outweighed. When making calculations for the weight per sack of poz-cement blends, the API guidelines and nomenclature need to be followed to avoid confusion and errors. In these blends, the content of pozzolan is based on the absolute volume of cement replaced by the poz. Absolute volume is the volume of the material per unit of mass without voids. This should not be confused with bulk volume, which includes the air around the particles of the material. Bulk volume is used to calculate storage requirements for bulk materials. For example, a 35-65 blend means 35 % by absolute volume of poz and 65% by absolute volume of Portland cement. In the API recommended nomenclature, the first number always refers to the poz, and the second to the cement. In this example, if the absolute density of the cement is 26 lb/gal (absolute volume: 0.0384 gal/lb) and the absolute density of the poz to be used is 20.5 lb/gal (absolute volume: 0.04878 gal/lb), then the equivalent weight of a "sack" of the blend is calculated as follows. Notice that the API defines one sack of Portland cement as weighing 94 lbs. Absolute volume of one sack of cement: (94 lbs/sk)/(26 lb/gal) = 3.62 gal 35% absolute volume occupied by the poz = 1.267 gal 65% absolute volume occupied by the cement = 2.353 gal Equivalent weight of a sack of the blend = 1.267 x 20.5 + 2.353 x 26 = 26.97 + 61.18 = 87.2 lb/sk Cement 3-17 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Notice that the calculations shown above define an equivalent sack of the blend as the weight of the blend in pounds that occupies the same volume as 94 lbs of the Portland cement being used. Once the equivalent weight of a sack of the blend is calculated, the concentration of additives included in the slurry design is based on that weight. For example, if 0.2% retarder will be used, the weight of retarder per sack of the blends is 87.2 x 0.2 = 0.174 lb. For laboratory and for filed bulk blending calculations, it is important to re-calculate the weight of the cement and the poz needed per sack of the blend: Weight of poz per equivalent sack of blend: 1.267 gal x 20.5 lb/gal = 25.97 lb Weight of cement per equivalent sack of blend: 2.353 gal x 26 Lb/gal = 61.18 lb Manufactured Light Weight Cements These cements are a good alternative to fly ash-cement blends. They minimize several of the quality control issues associated with the use of poz systems, and have similar or improved properties over field blended fly ash slurries. Trinity Lite-Wate This high sulfate resistant cement is manufactured by the Trinity Division of General Portland, Inc. It is a blend of Portland cement and calcined shale. The material is finely ground. Water content of the formulations can be varied from about 65 - 115 percent to generate high strength, lightweight slurries within a range of densities of about 11.9 - 13.7 lb/gal. The cement is available in bulk or packaged in 75 pound sacks (1 bulk cubic foot). Trinity Lite-Wate cement can be used in wells with temperatures up to 300 deg F (150C) without significant strength retrogression. TXI Lightweight This is also a high sulfate resistance, low-density cement that allows formulations of slurries in a density range of about 11.9 to 14.2 ppg, using water rations of from 55% to around 109%. It is a blend of Portland cement and calcined shale. The cement is available in bulk with a density of 75 pounds per sack (1 cubic foot). Like Trinity Lite-Wate, this cement can be used at elevated temperatures, and develops good levels of compressive strength. Rev. 01/2002


Cement Manual

Laboratory Testing of Cement Slurries The API 'Recommended Practice for Testing Well Cements' (API RP -10B), provides recommended testing devices and procedures to measure the performance properties of cement slurries to be used in wells. Thickening Time Thickening time often called "pumping time" is the time a cement slurry remains sufficiently fluid to be pumpable under downhole temperature and pressure. The thickening time must be long enough to allow the slurry to be mixed and placed without risk of premature setting. Desired thickening times are based on the estimated job time to pump the fluids, plus a safety factor. Excessive thickening time should be avoided to eliminate lengthy WOC (waiting on cement) times. The laboratory devices used to measure the thickening time of cement slurries are defined in API RP-10B. Cementing laboratories throughout the world have these devices known as consistometers. The apparatus allows agitation of the cement slurry under simulated well conditions of temperature and pressure, while measuring the consistency (an arbitary measure of viscosity) of the slurry. Depending on the design, a consistometer can simulate well conditions of temperatures as high as 500 deg F and pressures up to 30,000 psi. As the apparatus applies heat and pressure to the cement slurry, a continuous consistency measurement is recorded. The end of the thickening time test is when consistency reaches 70 or 100 Bc. Bc is an API defined empirical unit of consistency named in honor of Bob Bearden, a departed industry researcher. Tests are often terminated once the cement slurry reaches 70 Bc to facilitate removing of the gelled slurry from the testing cup before the cement sets hard, making the clean up operation easier for the laboratory technician – one of the unsung heroes of the oil-patch. Although RP-10B provides "test schedules" for testing thickening times for different well depths and temperature gradients, the test schedule for a given job needs to be calculated using the actual well conditions and the anticipated pump rates. The API schedules are ‘average circumstances’ and should be used only when insufficient information is available. As soon as this information on the actual job is obtained, the test needs to be re-run using a job-calculated test schedule. API RP-10B provides information on how to calculate job-tailored Cement 3-19 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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thickening time schedules. For example, the length of time to pump the leading edge of the cement slurry from the surface to the bottom of the hole (from the surface temperature to the bottom hole circulating temperature), needs to be calculated using the capacity of the casing to be cemented and the expected average job pump rate. Below is an example calculation of a job-tailored thickening time schedule. The job-tailored schedule is compared to the API "average" schedule for the same depth and temperature gradient. Well depth: 16,000 ft Liner to be cemented: 7 in., 34 lb/ft, 0.0354 bbl/ft., 2,000 ft long Drill pipe: 5-1/5 in, 24.7 lb/ft, 0.02119 bbl/ft Drilling fluid density: 13.5 lb/gal Spacer fluid density: 14.5 lb/gal Spacer length in the annulus: 500 ft Assumed pressure of the cement slurry as it leaves the cementing head: 300 psi Expected average pump rate during displacement: 5 bpm Temperature gradient: 1.7°F/100 ft BHCT: 284° Note: to be able to compare the calculated vs. the API schedule, we will assume that the well BHCT is the same as the one given by the API. In an actual case, this temperature would be refined using a numerical simulator and maybe log information. It could be different than the API BHCT. Pipe capacity: 14,000 x 0.02119 + 2,000 x 0.0354 = 296.66 + 70.80 =367.46 bbl Calculated time to bottom: 367.46/5.0 = 73.49 minutes API suggested time to bottom: 55 minutes Calculated heat-up rate (rate of heating of the slurry in the consistometer from the surface temperature, normally assumed to be 80°F to the BHCT): (284 - 80)73.49 = 2.78 °F/min. API suggested heat-up rate: 3.71 °F/min. Calculated bottomhole pressure above the cement slurry: 0.052(15,500 x 13.5 + 500 x 14.5) = 0.052(209,250 + 7,250) = 11,258 psi API suggested final pressure: 11,400 ft Well-tailored initial test pressure: 300 psi API suggested initial test pressure: 1,200 psi Rev. 01/2002


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Calculated pressure-up rate: (11,258 - 300)/73.49 = 149 psi/min. API suggested pressure-up rate: 185 psi/min In addition, if the top of the cement column temperature is known or estimated, it is possible to adjust the tailored schedule to simulate the cement moving up the annulus. This is often not done since normally the circulating temperature at the top of the column is not known. The RP-10B contains the equations needed to make this schedule adjustment. As can be seen, a well-tailored thickening time schedule can be quite different from the "average" API schedule. If the cement slurry for the job is not tested using a realistic schedule, this could lead to incorrect additive concentrations in the final slurry, and in the worst scenario, job failure. Fluid Loss Cement slurries are frequently pumped across permeable zones with a positive pressure differential. As with muds, a positive pressure differential is maintained to prevent a kick. Cement filtrate will pass into the formation even though a drilling fluid filtercake is present. A small amount of cement dehydration (loss of filtrate) is generally acceptable, but severe dehydration of the cement slurry will alter the performance properties of the slurry including thickening time and rheology. With dehydration, the cement will set earlier due to the lower water/cement ratio and the loss of retarder. In extreme cases, cement can "block off" the annulus terminating the job. It is therefore important to control the fluid loss rate in cement slurries. The following conditions make control of fluid loss of the cement slurry more critical:

• Squeeze operations (level of fluid loss controlled based on the results of the injection test)

• High zone permeabilities • Large differential pressures, for example across depleted or partially depleted zones

• Narrow annular clearances, for example when cementing liners • Poor mud properties A well formulated mud system, even with a high overbalance of several thousand psi, will produce a low permeability filtercake which will prevent loss of filtrate from the cement. It can be argued that, in many cases, the fluid loss control in the cement is an unnecessary added expense. However, it is well established Cement 3-21 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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practice to control fluid loss from cement slurries across permeable zones. A poor mud cake will do little to control cement filtrate loss, but it will also hinder mud removal and lead to poor isolation. Good fluid loss control in the cement will not fix that! Cement slurry filtration under pressure against a permeable medium is normally measured in the laboratory under static conditions with a high pressure filter press, using API (RP-10B) established test procedures. The press is essentially the same used to measure fluid loss of drilling fluids. The significant difference is that the filter medium is a No. 325 U.S. standard sieve series wire screen instead of filter paper. Normally, the slurry is placed in a HPHT consistometer and the appropriate thickening time test schedule is followed. Upon completion of the schedule and an additional 30 minute conditioning period, the slurry cup is removed from the consistometer and the slurry is poured into the pre-heated high-pressure filter press. The filtration is maintained for 30 minutes at 1,000 psi differential and at the BHCT. For slurries that dehydrate in less than 30 minutes, estimated 30-minute fluid loss values are obtained either by plotting the results on log-log paper and extrapolating to the 30-minute value or by using the following formula: Q30 = 2Qt x 5.48/(t)1/2 Where: Q30 = Extrapolated 30 minutes filtrate Qt = Measure volume of filtrate at time t A better way to measure the fluid loss of cement slurries is to use the apparatus known as the Stirred Fluid Loss Cell This is specialized equipment that combines the functions of a conventional, static fluid loss test cell, with the slurry conditioning capabilities of a consistometer. With the Stirred Fluid Loss Cell, the slurry is placed in the test cell and brought to bottom hole temperature conditions (there is a 2000 psi testing pressure limitation) while stirring. The slurry is conditioned at bottom hole conditions for an additional 30 minutes. After the conditioning period is completed, stirring is stopped, the cell is inverted, and the 1000 psi pressure differential is applied in the normal manner for conducting a fluid loss test. A procedural advantage of using this apparatus is that there is no need to cool the slurry in the consistometer, to be able to remove it from the device, if the test temperature exceeds 190F. Rev. 01/2002


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The main advantage of this device is that it simulates the cementing job conditions more closely than when using the static cell. One disadvantage (the same as for the static cell) is the limitation on working pressure, as mentioned earlier. Another shortcoming is that in reality, this is still a static, rather than a dynamic test, because stirring of the slurry ceases prior to the application of the differential pressure, and the filtration test is run with the slurry under static conditions. Testing of the cement fluid loss at the BHCT is critical since fluid loss additives are temperature sensitive. Normal range of concentration for fluid loss materials, based on weight of cement, is about 0.5% to 1.5%. Levels of fluid loss normally used throughout the industry are 50 to 300 milliliters/30 minutes for squeeze work (depending on the injection test), around 150 to 250 for cementing casing (depending on the annular clearance, permeability exposed, etc), and as low as 50 - 20 milliliters for cementing of liners, particularly if potential for gas migration existent. Viscosity (Rheology) Rheology is the technical term used to describe the shear rate - shear stress behavior of a fluid. The rheology of a cement slurry needs to be measured to allow predictions of the pressure drop and the flow regime of the slurry at projected job flow rates. These calculations are normally performed using computers. In addition, the rheology of the slurry can help the experienced engineer decide if the fluid will be easy to mix in the field, and/or if the slurry will tend to segregate (settle). The API document RP-10B contains two detailed chapters dealing with the determination of the rheological properties of cement slurries, and with methods for calculating pressure drop and flow regime in pipes and annuli. Cement slurry rheology is normally measured using a portable, atmospheric pressure rheometer. Two different instruments are available. The Fann V-G meter and the Chan V-G meter. The two devices function in essentially the same way. The maximum temperature than can be used with these rheometers is about 190F. Cement 3-23 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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A few HPHT instruments are available throughout the industry. For critical wells, HPHT instruments need to be used to better estimate the behavior of the slurry and of the cementing job. As an example, the Fann V-G Meter is a direct-indicating rotational-type viscometer powered by a two-speed synchronous motor to obtain rotational speeds of 600 rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The outer cylinder or rotor sleeve is driven at a constant rotational velocity for each rpm setting. The rotation of the rotor sleeve in the cement slurry produces a torque on the inner cylinder or bob. A tension spring restrains the movement. A dial attached to the bob indicates displacement of the bob. The tension spring most commonly used is known as a "number one" spring. The #1 spring was designed for studying drilling mud. The higher rheologies of a cement slurry may cause a viscometer fitted with a #1 spring to "peg out". A spring with a constant twice that of the #1 spring is available and is called, appropriately, a "number two" spring. If a #2 spring is used, the viscometer dial readings are doubled to convert them to the readings that would have been obtained using a #1 spring. In effect, a #1 spring allows readings to be taken from 0 to 300 degrees while a #2 spring allows readings to be taken from 0 to 600 degrees. Viscometers equipped with #2 springs are often used because they allow more complete data to be collected for slurries that have higher consistencies.

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Figure 7 shows the rheological behavior of a neat cement slurry measured using a Fann VG meter. The shear stress - shear rate response was curved fitted using the Power Law model.

Figure 7: Rheology of a Neat Cement Slurry Curve Fitted Using the Power Law Model Gel strength Development As cement slurries hydrate, they develop gel strength. Gel strength is essentially the result of the hydrated structure discussed in a previous section. It is also influenced by the charges on the particles in the mix water. If a cement slurry is allowed to remain static for a period of time, it will gel to a degree that depends on the formulation of the slurry, the temperature and pressure, the time since the slurry was mixed, and the length of time the slurry remains static. A knowledge of the gel strength development behavior of a cement slurry is important since if, for some reason, the slurry becomes static in the well and develops high levels of gel strength, it will take high pump pressures to break the gels. These high pressures may cause breakdown of weak formations in the well. In addition, static gel strength development in the annulus causes a pressure drop in the cement column. Depending on the magnitude of this pressure drop, and the fragility of the structure in the cement, this may allow invasion of formations fluids into the wellbore. Cement 3-25 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The API RP-10B recommended practices document gives a test procedure to estimate the gel strength development of cement slurries using the Fann or Chan V-G meter. The procedure utilizes the lowest speed of the instrument to measure the gel strength (normally the 3 rpm). For purposes of comparison among different slurries and even for the estimation of the start-up pressures after a short shut down period, this method is fine. However, for the estimation of the pressure drop of a cement column to determine the time for potential fluid invasion of the cement column under downhole conditions, the API method is totally inadequate, and should not be used. For estimation of the potential for formation fluid influx, a measure of the gel strength development under downhole conditions needs to be made. The Fann or the Chan V-G meters are not capable of measuring the gel strength development at the needed accuracy. These laboratory instruments can test fluids only at atmospheric pressure and at a maximum temperature of about 190×F. In addition, the 3 rpm speed (normally the lowest available speed with these instruments) is too high to measure true gel strength. This speed causes the gels to break at the rotor interface, defeating the purpose of trying to measure the strength of the weak gels as they develop. The measurement of gel strength development needs to be made with the fluid static, taking great care not to break the gels as they develop. Two methods are available to the industry to perform accurate measurements of gel strength development. One is that developed by Halliburton know as the MACS. The MACS (Multiple Analysis Cement Slurry) Analyzer is a lab device used to measure the static gel strength characteristics of fluids vs. time, at downhole conditions of temperature and pressure (400×F and 10,000 psi max.), with minimum effect on the developing gels (rotation speed is as low as 0.2×/min). Below is an example of a MACS test run on a cement slurry. Another method utilizes ultrasonic pulse techniques to measure the development of the static gels. This recently developed capability can be added to the UCA (Ultrasonic Cement Analyzer) which is used to measure the strength development of cements vs. time (the UCA is discussed later in this section).

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500

Gel Strength (lbf/100ft)

450 400 350 300 Gel Strength

250 200 150 100 50 0 0

20

40

60

80

100

120

140

160

Time (min)

Figure 8: Gel Strength Development Using the MACS Recently, Schlumberger has developed a version of the vane rheometer for simulated downhole conditions. The device is not well known or readily available throughout the industry. Free Fluid – formerly known as Free Water Free Fluid is the liquid (water and dissolved chemicals) that separates from the bulk of the cement slurry under static conditions. The amount of free fluid depends on several variables including the composition of the cement slurry, the temperature, the mixing and conditioning history, etc. Its measurement is dependant on the method used. Again, the API RP-10B contains several methods to measure the separation of "free" fluid. Free fluid is an indication of the stability of the cement slurry. Cement slurries with high levels of free fluid (normally ~2+% of the slurry volume) often tend to segregate or settle out under static and/or dynamic conditions. This behavior can produce cement columns that are non-homogeneous from top to bottom. In addition, in deviated holes, free fluid can generate a fluid channel on the high side of the hole. This channel can easily allow migration of formation fluids along the cemented annulus. Cement 3-27 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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In the API “operating free water test,” the slurry is heated to BHCT (or BHSQT for squeeze operations) in a pressurized consistometer in accordance with the appropriate schedule, cooled to 194×F (if needed) and then transferred into a 250 ml graduated glass cylinder. If the free fluid test is going to be conducted above room temperatures (maximum of 176 deg F according to API), the graduated glass cylinder is placed in a pre-heated curing chamber or water bath for the duration of the test. The cylinder is sealed to prevent loss of fluid through evaporation, and then allowed to remain quiescent, on a vibration-free surface, for the two-hour duration of the test. In an attempt to determine free fluid under more realistic downhole conditions, the test is sometimes conducted with the cylinder at an angle, particularly for highly deviated or horizontal wells. Since the 45× angle is a severe case for free fluid occurrence, it is often used as a default (all the free fluid tests run at this angle). Holding the cylinder at an angle simply amplifies the free water by providing a shorter settling path for the cement particles. The preferred free fluid content of cement slurries, particularly for critical wells is zero. This is particularly so for highly deviated or horizontal wells. For near vertical wells, the maximum allowed free fluid content should be 1.0%, unless potential for gas or water migration after cementing exists. In that case, the slurry should be designed for zero free fluid, regardless of the well angle, tested at conditions as close as possible to those to be encountered downhole. Strength Development The conventional way the oil industry has determined strength of cements is by measuring unconfined compressive strength on 2” cubes cured for different periods. This approach is borrowed from the construction industry and is a useful comparative method for different slurry types and designs. The strength requirement for oil well cements depends on several factors. In general, the cement must have sufficient strength to secure the pipe in the hole, exclude undesirable well fluids, and withstand the shock of drilling, completing and subsequent production loads. Rev. 01/2002


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In fact, cement needs very little strength to support casing. It is generally accepted that cement tensile or shear strength is around 10% of the compressive strength. A few feet of cement sheath with as little as 50 - 100 psi compressive strength can support several hundred feet of casing. However, filler cements with much higher strengths (1000+ psi) are normally used. It is also common practice to use even higher strength cements (2000+ psi) around the shoe joints and across potential pay zones. This practice of using high strength cements across the pay zones has been investigated in some detail lately, and available information suggests that very high strength cements, because they tend to be brittle, may not be the best cements to perforate. Lower strength cements, with around 1000 psi compressive strength have been used and perforated across pay zones with good success. Also, foamed cements are used routinely in many wells across the pay zones with excellent results. Another rule of thumb is that for drilling ahead, the cement needs to develop ~500 psi compressive strength. For offshore applications, however, this practice can be very conservative (long WOC times). For those locations, WOC times have been lowered with good results to the time when the cement has developed ~100 psi. One reason why the industry has looked for high strengths is the effect that even quite low levels of contamination can have on strength. High strength buys extra comfort. Temperature has a pronounced effect on the strength development. Up to around 230F, increasing temperatures increase strength. However, at higher temperatures than this, decreased strengths are observed with increasing time. This behavior is known as strength retrogression. In order to prevent it, cement formulations exposed to downhole temperatures above 230 deg F are formulated with the addition of about 35% of fine silica. 230 deg F is a rather arbitary cut-off figure. Just below this temperature cement strengths are extremely high and the cement is very brittle. The fact that higher temperatures result in somewhat lower strengths should be seen in context. Above (say) 260 deg F, silica is certainly needed. Cement 3-29 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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API RP-10B includes two methods to measure the strength development of cements. One is the destructive test referred to above using 2 inch cubes cured in moulds at simulated downhole conditions. The other uses a special device known as the Ultrasonic Cement Analyzer (UCA). With this instrument, a sample of cement is held in a pressure cell and subjected to insitu ultrasonic pulse velocity measurement. Again API RP-10B test schedules are used to heat up the sample. Pressures used are generally about 5,000 psi, but the test equipment can be used to much higher pressures (as high as 20,000 psi). Measurements of the cement's ultrasonic pulse velocity are started during the fluid state and continue through the initial set to any desired time. Strength values are continuously computed and displayed until the test is terminated. The result is a complete history of the initial set and the strength development. Figure III-8 gives an example of the UCA test. The principal advantage of the UCA is that it allows determination of compressive strength continuously vs. time. In addition, the measured transit time of the cement can be used to help "fine tune" ultrasonic devices used in the field to determine the condition of the cement behind the pipe. Other advantages are simplicity of the test, and the low level of labor required. Once started, the device can be left to collect data for long periods of times without attention. The main disadvantage of this method is that the compressive strength of the cement is inferred from correlations developed between transit time across the sample and compressive strength. Three correlations are generally programmed in the instrument for low, medium and high density/strength cements. At the start of the test, the technician selects the correlation to be used. Pulse velocity is every bit as useful a measurement as unconfined crush tests. In general, the predictions of strength development when using the UCA, when compared to the destructive test discussed above, are found to be conservative. In other words, the strengths predicted by the UCA tend to be lower than from the cube method at the same curing conditions. With either one of the methods described above, curing schedules and test parameters need to be adjusted to reflect as closely as possible the conditions of the well. For example, the testing schedule should be modified as needed to be able to measure the compressive strength development of the cement at the top of the cement column. The API RP-10B gives guidelines to accomplish these schedule adjustments. Rev. 01/2002


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Figure 9: UCA Test: example chart Settling Behavior Solid segregation, or settling, downhole under static and/or dynamic conditions is a serious concern in drilling operations. Barite sag is well recognised in the industry and poorly designed cement slurries and spacer fluids can behave in a similar manner. The concerns occur particularly in highly deviated and horizontal wells. Settling of solids from these fluids can cause problems including:

• • • • • •

stuck pipe, e.g. liner running string kicks pack-off, gas and/or water migration after cementing failed primary cement jobs failed cement plugs Cement 3-31 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Some investigators have thought that settling occurs mainly while the fluids are static in the well. Although static settling occurs, other work indicates that dynamic settling (while pumping) may be a problem too. The best way to determine if a fluid will settle is to test it in the laboratory under downhole conditions of temperature and pressure. Static Settling Test API RP-10B describes a static settling test that is widely used throughout the industry. In essence the test consists in placing a sample of cement slurry in a tube and allowing the cement to set under downhole conditions. The depth to the top of hard cement is measured and then the tube is split to allow removal of the set cement column. The column is then cut into sections and the density of the different segments measured. From the data, a density profile is constructed, and the user then decides if the slurry design is acceptable from the point of view of segregation or settling. The Figure shows a sketch of the API sedimentation tube. Settling Test Tube The main advantage of the API test is that it is quantitative in nature. The user is able to "measure" the settling or segregation tendencies of the fluid. The other advantage is that the method is very well known throughout the industry often as the ‘BP Settling Test’. The main drawback is that it takes time to obtain the results of the test. The cement is usually allowed to set for 24 hours before removing it from the tube. This may present a problem if the slurry is being optimized, and the the job is approaching. Another test method uses a consistometer to bring the cement slurry to downhole conditions of temperature and pressure. After a period of conditioning at BHCT, the motor of the consistometer is stopped, the slurry is kept static for 10 to 30 minutes, and without re-stirring, the slurry is removed from the tests apparatus and examined for static settling. Measurements of the density of the slurry are made at several depths in the slurry cup to try to quantify the setting/segregation tendencies of the slurry. The bottom of the cup is carefully examined looking for settled/segregated solids. This procedure has been very successful in detecting static settling/segregation of cement slurries, spacer and drilling fluids. Rev. 01/2002


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The main advantage of this method is time, taking even less than a thickening time test. Because of the size of the slurry cup, the tests is not affected by wall effects. Dynamic Settling Test Dynamic settling (settling during pumping of the fluid) can be critical especially in highly deviated, ERD and horizontal wells if the potential for gas or water invasion exists. Tests have suggested that it is possible for a cement slurry to show very little static settling, but have serious dynamic settling. One possible explanation for this phenomenon is that statically, the fluid is allowed to develop gel strength which contributes to solids suspension. Under dynamic conditions, gel strength is not developed, and if the fluid does not have enough viscosity at downhole conditions, solids may settle out. Low flow rates will exacerbate the problem. The API RP-10B does not contain a dynamic settling test. However a procedure which was developed by a major oil company is available. Service companies are familiar with the test and are capable of performing it. The laboratory procedure requires a variable speed consistometer equipped with a special slurry cup paddle that allows detection of dynamic settling. The fluid is brought to downhole conditions of temperature (BHCT) and pressure using a thickening time schedule, stirring at 150 rpm (normal rotation speed). Once the cement slurry is stabilized at bottom hole circulating temperature and pressure, the rotation speed of the consistometer is reduced to 20-30 rpm. Rotation at the low rpm is continued for a minimum of 30 minutes then the cup is removed from the consistometer and opened without turning it over. The standard cement slurry cup paddle is intended to maintain the entire slurry agitated and homogeneous. The paddle used to detect dynamic settling likewise keeps the fluid stirred throughout the entire cup at high rpm, but allows solids settling at the low rpm


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Once settling starts to take place, this is apparent on the consistency chart. The solids at the bottom of the cup start to load and grab the paddle and the recorded consistency starts to increase or to look “jagged”. The final confirmation of the existence or nonexistence of settling is after the test, when the slurry cup is opened and the fluid examined for settling. The height of the cone of solids at the bottom of the paddle is measured and recorded. A true non-settling fluid will not form a cone on the bottom plate of the paddle (zero cone height). The maximum cone height normally allowed is 1/2 in. Another criteria is that for lightweight slurries, more than 1/2 lb/gal difference from top to bottom of the cup is not accepted. For weighted slurries, more than 1 lb/gal difference from top to bottom of the cup is not permitted, particularly in a critical job.

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Cement Slurry Design Slurry Design Aims: Understand the properties of cement slurries and ways in which they can be modified to suit the aims and objectives of the job. Understand the function of cementing additives and when it is necessary to use them. Become familiar with the laboratory test methods, test equipment and the interpretation of the results from standard tests. Slurry Properties Required

The properties which are generally considered to be important include: • Density – this may need to be high to control the well or low to prevent fracturing weak formations

• Fluidity to enable pumping and placement • Setting time, or pumping time, so that the slurry sets soon after the job is complete and the subsequent operations can begin.

• Strength – this may or may not be important. A kick-off plug may need a high strength.

• • • • •

Stable suspension of particles – non-sedimenting. Free Fluid or free water Ability to resist dehydration against permeability – Fluid Loss Permeability Shrinkage Durability. The cement must last a long time – longer than the well – and prevent fluids moving between the subsurface and surface.

Cement Slurry Mixing Water Ratio The optimum water to cement ratio for a cement slurry is the result of a balance between opposing trends. On the one hand, low water to cement ratios generate dense, high strength set cements. Test have suggested that the maximum cement strength is obtained at a water-cement ratio of about 2.8 gallons of water per sack of cement. This is the minimum amount of water necessary to fully chemically react and hydrate the cement particles. Cement Slurry Design 3-35 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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However, this cement-water slurry would have the consistency of caulk, or toothpaste, and could not be pumped down a well. On the other hand, high water to cement ratios reduce slurry density and give low slurry rheologies that facilitate mixing, reduce frictional pressures and allow pumping with field equipment. Too much mixing water de-stabilizes the slurry, causing free fluid and settling/segregation of the particles. In addition, high water to cement ratio slurries produce low strengths. Therefore, one of the primary slurry design issues is the balance between density (usually determined by the well circumstances) and the fluid and set properties.

Quality of the Mixing Water Whenever possible, potable (drinkable) water should be used to mix the cement slurry. However, fresh waters are not always available. For example, offshore, sea water is often used to mix the slurry. In remote locations, low quality (contaminated) water may be the only source available. In many cases non-potable waters can be used with care, but the slurries must be lab tested using the actual field water to be used in the job. Additive concentrations and response will vary depending on the water source. Field waters sometimes come from open pits or from shallow water wells, streams or lakes. These waters are often partially contaminated. Contaminants in mixing waters include:

• • • • •

fertilizers dissolved in rain water, waste effluents in streams, including animal waste soluble agriculture products such as sugar cane or sugar beets, rotting vegetation (swamp waters), Dissolved salts from nearby caves, underground waters, etc.

Depending on the concentration, these materials can seriously alter the set and other properties of the cement slurry.

Density The well design will normally fix a range for the slurry density. This will be influenced by the height to which the cement is to be lifted, e.g. 500ft MD inside the previous shoe, and the available pore/fracture pressure window. The slurry density will normally be higher than the mud density. A lead and tail system (a lighter slurry followed by a heavier slurry) may be used to reduce total pressure at the shoe and avoid losses. Each API Class of cement has a 'normal' water ratio for a neat (no additives) slurry. The water-cement ratio for each API class is given in as gallons of water per sack of cement (94 lbs) and as percent water (pounds of water per 100 pounds of cement). Rev. 01/2002

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The slurry density and yield are also given in the table. The slurry density is shown in pounds per gallon and the slurry volume (yield) in cubic feet per sack of cement. Figure 10: API Normal Cement Slurry Densities API Cement Class

Mixing gal/sack

Water %

Weight lb/gal

Volume cu ft/sk

A

5.2

46

15.6

1.18

B

5.2

46

15.6

1.18

C

6.3

56

14.8

1.32

G

5.0

44

15.8

1.15

H

4.3

38

16.4

1.06

D,E,F

4.3

38

16.4

1.06

For a given well application, the density of the slurry required does not always match that given above. It may be possible to use a tail slurry with the above weight and use a lighter lead slurry above it. The lighter, lead, slurry can be achieved by basically two approaches:

• Increasing the water/cement ratio • Including light weight particles – particles with a density less than the cement

Fluidity The ability to mix the cement slurry on the fly, or in a batch mixer, is obviously important. In addition, the cement slurry must be placed in the annulus without excessive friction pressures that may exceed the fracture gradient. Conversely, if the slurry is too thin, problems with stability/settling and free fluid will develop. The rheology of the slurry is an important parameter that enters into the displacement/placement efficiency consideration discussed later. When necessary, the rheology of a thick slurry can be reduced with additives called dispersants.

Controllable Setting Time For drillers, the thickening time is the most critical property of the cement slurry. The slurry must not set before the placement operation is completed but must set fast once in place. Cement needs to develop strength fast to support and protect the pipe, and for the drilling engineer to be able to proceed with drilling or completion. So, a controllable thickening time is needed. Cement Slurry Design 3-37 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The thickening time of a cement slurry is extremely dependent on temperature. It can be controlled by the use of chemical accelerators or retarders. The job time plus one or two hours is a common rule.

Sufficient Strength Cement needs to develop strength to protect and support the pipe, and to allow subsequent operations in the well. However, just how much strength is needed for proper protection and support of the casing is not well understood. It is likely that, in general, the industry uses cements that develop more strength than is needed. Cement contamination with well fluids that can dramatically reduce strength so this is good insurance. However, high strength cements are brittle, and recent studies have suggested that the industry needs to consider using lower strength cements (below 2000 psi) across pay zones. Some of these lower strength cements are better able to withstand casing perforating and loads imposed by pressure and temperature changes in the wellbore, without damage to their integrity. The poor understanding of strength requirements is, in part, due to the very simplistic crush test used in the industry. This unconfined 2” cube test is really only of any use as an indicator of strength development and as a means of comparing different samples. The numbers generated are not useful in design calculations where complex loading needs to be addressed. The strength development of cements depends mainly on temperature and the water/cement ratio. Low well temperatures tend to cause slow strength development. This can presents a serious design challenge for shallow casing strings and/or low temperature environments like the North Slope and in deepwater locations. On the other hand, elevated temperatures accelerate the development of strength. At temperatures above about 230F, powdered silica needs to be added to the cement to avoid the phenomenon known as ‘strength retrogression’. The compressive strength development of the slurry is normally measured only after the other properties have been determined and optimised. If the strength developement is acceptable, the cement slurry formulation is considered satisfactory.

No Permeability Protection of casing and prevention of fluid migration within the cemented annulus during the life of the well requires set cements to have very low permeability once fully set. Fortunately, cements normally develop very low levels of permeability. The Table below shows examples of permeability values for several neat cements. Rev. 01/2002


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Figure 11: Water Permeability (md) of Some Neat Cements After 7 Days of Curing Temperature F

API H (1)

API A (2)

API C (3)

80

0.00218

0.000167

0.0000000537

120

0.000001

0.000241

0.0000000613

140

0.000175

0.0.0213

0.0000000459

160

0.000983

0.0172

0.0000000915

(1) course ground, 40% water (2) medium ground, 46% water (3) fine ground, 70% water

Set cements, cured at temperatures less than 230F develop very low permeabilities, much lower than those of producing formations and similar to those of shales. However, the final permeability of a cement is a property over which normally, relatively little control can be exercised. The API RP-10B contains a procedure to measure the permeability of set cements but, under normal conditions, not much attention is given to the permeability of the set cement, and permeabilities are not often measured. Cements subjected to high temperatures – higher than 230 deg F – which have not been stabilized against strength retrogression will show increased permeabilities with age due to the chemical phase changes. The Figure illustrates this effect. Stabilisation with around 35% silica bwoc will prevent high permeability. Figure 12: Effect of Temperature on Permeability


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No Shrinkage Shrinkage is perhaps the most misunderstood and controversial property of oil industry cements. The main reason is that the problem is complex. The API has published a pamphlet (API Technical Report 10 TR2) on expansion/shrinkage of cements that attempts to explain the phenomenon and better define the terms. Shrinkage and expansion of cements results from the formation of hydration products having densities which differ from those of the reacting components. These hydration reactions can cause: • Changes in pore volume of the cement matrix • Changes in pore pressure in the matrix • Changes in the cement physical dimensions • Changes in internal stresses The actual behaviour depends partly on whether the cement is able to draw in extra fluid or gas from the surroundings. When cements are sealed in totally impermeable membranes – as they would be if used in an inflatable packer, ECP, – then bulk volume shrinkage of around 2% is measured. If the cement is against permeability – say a water bearing sand – and extra water can be sucked into the sample as the hydration proceeds, then the total of the inner and bulk shrinkage is around 6%. This inner, chemical, shrinkage is related to the development of internal porosity and permeability Not surprisingly, temperature can also influence the resulting behaviour. One reason for the confusion around shrinkage is related to the time at which measurement starts. If cement is mixed with water, conditioned, then sealed in a membrane while it is still a pumpable slurry; then the bulk volume change, measured from this early time, follows the curve shown below. It may never ‘expand’ since it will not cross the axis. However, if the sample is allowed to set solid and then the measurements are started then the cement is seen to be expansive (see the new origin ‘Time Zero’ on the curve).

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Expansion

Mix with water and start measurement while still a liquid

Log time liquid

solid Time zero

Contraction

For cement inflated packers, cement shrinks and the sealing has to be compensated for by the rubber. In a normally cemented annulus, early shrinkage may be compensated for by movement (compaction) of slurry. The negative pressure developed during hydration of the cement can draw in gas from the formation. This effect, coupled with other properties of the slurry, can lead to gas migration and an incomplete annular seal. So-called expanding cements should only be used in extreme cases and where their behaviour is understood in detail. When an unrestrained annular ring of cement expands, the hole in the centre gets bigger not smaller. In a weak formation, cement expansion can produce a micro-annulus.

Long term durability One very substantial benefit of cement is that it has an established track record for durability – both in the oil industry and the construction industry. The mechanisms of degredation are well understood and, in general, cement once placed and set will remain to provide a pressure seal for a very long time – hundreds of years. There are however some circumstances where this fails. Attack by acid gases – this can cause quite rapid degredation. The best defence is a low permeability – this is obtained through reduced water content and through the use of particles within the slurry, e.g. latex. Cement Slurry Design 3-41 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Strength Retrogression at temperatures higher than 230 deg F – addressed by the addition of silica Severe cycling of pressures and/or temperatures – this can lead to cracking and eventual movement of fluids. Foamed cements may help to mitigate. Formation movements due perhaps to reservoir compaction or tectonic stresses. The casing may suffer considerable deformation but still remain intact but the cement sheath may crack and allow migration of fluids.

The Use of Cement by the Oil Industry Cement is a relatively low cost material that has proven quite reliable for sealing wellbores. Long term integrity of cements is well proven and, in general, the integrity of hydrocarbon producing wells has been satisfactory. This has been the testimony from operators who have used cement in thousands and thousands of wells throughout the world with good results. There are other materials that could be considered, for example some resins and various inorganic systems, but these materials have limited application due to their higher cost and chemical reactivity (difficult to control at high temperatures). Another reason for the use of cement is its availability world-wide, due to the use of cement in the construction industry. It is relatively easy for a cement plant producing construction cement, to also be able to manufacture API type cements. Many cement manufacturers throughout the world are producers of monogrammed API cements. Sometimes the quality of local cements is not the best, but with the use of additives, the cements can be made to work under downhole conditions.

Cementing Additives Methods to Adjust the Slurry Density There are basically just two ways to adjust cement slurry density,

• modify the water content • add particles In practice, it is often a combination of both approaches that is used. Particles have either low or high specific gravity depending on whether the intention is to reduce or increase the slurry density. Often these density controlling additives require additional water to be included in the formulation to maintain the desired consistency, or the use of some concentration of dispersant. Rev. 01/2002


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Adjusting the Water Concentration to Change Slurry Density The simplest way to modify the slurry density is by changing the water to cement ratio. For example, densified slurries can be designed by reducing the water concentration to levels that can produce densities of around 17 - 17.5 lb/gal without the need of adding high density additives to the formulation. On the other hand, light density slurries can be designed by increasing the water concentration from the normal values. When designing light weight slurries by adding extra water, additives need to be included to 'tie up' the water and prevent slurry instability. One way to tie up water is to add a clay. Bentonite is the most common clay used in the design of light weight slurries. The clay hydrates and allows high concentrations of water to be used while still maintaining good slurry consistencies and slurry stability. Bentonite will absorb about 11 times its own weight of fresh water. In cement slurries, however, the water absorbed or retained by a good quality bentonite is about 6 pounds of water per pound of bentonite when the bentonite is dry blended with the cement. If the bentonite is fully yielded by prehydrating it with the mix water and then using the bentonite-water slurry to mix the cement, it is possible to approach the level of 11 lbs of water per pound of bentonite. The next table gives examples of some slurry formulations using bentonite. Class G Cement with Bentonite Figure 13: Dry Blended:

Percent Bentonite(1)

Mix Water gal/sk

Slurry Weight lbs/gal

Slurry Volume cu ft/sk

0

5.0

15.8

1.15

2

6.3

14.8

1.34

4

7.6

14.2

1.52

6

8.9

13.6

1.71

8

10.2

13.2

1.89

10

11.5

12.8

2.08

12

12.8

12.6

2.26

(1)Percent by weight of cement Cement Slurry Design 3-43 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Figure 14: Prehydrated: Percent Bentonite(2)

Mix Water gal/sk

Slurry Weight lbs/gal

Slurry Volume cu ft/sk

1.5

7.3

14.2

1.46

2.0

8.4

13.7

1.61

2.5

10.8

12.8

1.94

3.0

12.7

12.3

2.20

3.5

13.5

12.1

2.31

4.0

15.5

11.8

2.58

4.5

19.5

11.2

3.13

(2)Percent by weight of cement

Sodium Metasilicate Sodium Metasilicate is available as a dry powder for dry blending or as a liquid for mixing in the cement mixing water. Most of the Sodium Metasilicate used by the industry is in the liquid form. This material is capable of taking-in large volumes of mixing water, allowing slurry densities down to 11.5 lbs per gallon to be mixed with little to no free fluid separation. Although the additive is a mild accelerator, at the low densities, the strength development of the cements is quite poor. This material should not be used at temperatures above about 150 F because conventional retarders needed at high temperatures tend to destroy the effectiveness of the additive. In addition, salt concentrations about 5% by weight of water (bwow) should not be used with this material. Some slurry formulations using Sodium Metasilicate are shown in the following Table. Figure 15: Class H with Liquid Sodium Metasilicate - Fresh Water Silicate gal/sk

Weight lb/gal

Yield cu.ft/sk

Total Mixing Liquid gal/sk

0.563

11.5

2.74

16.93

0.338

12.7

1.96

11.05

0.225

14.0

1.51

7.68

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Using Particles to Lower Slurry Density There are several materials that can be used to reduce slurry density. We will review several of the most commonly used. Hollow Spheres The most commonly used hollow spheres are fly ash 'floaters', a by-product of the coal burning process. The material has an specific density of about 0.685 at atmospheric conditions, and a bulk density of about 25 lb/cu.ft. The use of this additive allows cement slurry densities as low as 10 lb per gallon with reasonable strengths. Cement compositions containing hollow spheres are hard to design, to make sure the spheres do not float out of the slurry. The recipes are also hard to blend due to the light density of the spheres. In addition, because increasing pressures tends to collapse portions of the spheres, the density and yield of the slurries change with pressure. The currently used hollow spheres are competent to about 6,000 psi. Nitrogen - Foam Cements Nitrogen has been used to generate foam cement slurries in the oil industry for over 20 years. Initially, the primary application was solving severe lost circulation problems almost exclusively on land wells. The main benefit was providing ultra-lightweight cement systems that could be applied at densities of less than 11 lb/gal and gain good strength rapidly. Application of foam cement then grew to include squeeze cementing of weak zones which would not hold a column of conventional cement without going on vacuum during the job. More recent applications have included prevention of water flows when cementing surface casing in deep-water applications in the Gulf of Mexico and other areas of the world. Foam cements provide a means of placing a light, competent cement across weak formations, with minimum losses. Additionally, foam cements have the unique property of “compressibility-maintained, hydrostatic pressure” across high pressure gas and water zones, as the cement goes through the transition from a liquid to a solid. Foam cements have overcome the problems associated with conventional cements for this application. Conventional cements are not compressible and readily loose hydrostatic pressure while going through the transition phase, potentially leading to influx of gas or water into the cement column (flow after cementing). Foam cements have also been used recently in HPHT wells due to their high ductility, to eliminate cement failure caused by temperature and/or pressure changes during the life of the well. Conventional cements have been found to fail (crack) under those conditions. Physical properties and some advantages of foam cement technology are outlined below. Cement Slurry Design 3-45 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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1.

High Strength / Low Density: Foam cements have the highest strength at a given (low) density of any cement system available. This is due to the fact that the base slurry (unfoamed) is typically a conventional high strength cement. The addition of nitrogen (gas typically used to generate foam cement) does not reduce the overall strength of the system to the extent of other lightweight additives used in cement (excess water, microspheres, etc.). Foam cements can be generated at densities much less than conventional lightweight cements with sufficient strength for completion purposes. Because of this, foamed cement can be placed in a single stage without loss of circulation in situations where conventional cements could not.

2.

High Viscosity: When a fluid is foamed it typically develops significantly higher viscosity than the unfoamed base fluid. Because of the highly energized nature and viscous nature of foam cement fluids, better mud displacement can be expected with foam cement in comparison to conventional cement systems. Better mud displacement can ultimately mean better protection of the casing and sealing of the annulus, helping to eliminate costly squeeze cementing operations and other repair work.

3.

Ductility: Set foam cements have been found to be significantly more ductile than conventional cement systems. This ductility can help improve the durability of the cement sheath over the life of the well. Successful applications of foamed cements in wells with the potential for stress-induced failures due to temperature and pressure cycling have been reported in the literature.

4.

Compressibility and Fluid Loss Control: The gas phase of the foam cement causes the unset slurry to have significantly more compressibility than conventional cement slurries. Also, foamed fluids by nature have a degree of built-in fluid loss control. Both of these properties can help prevent gas and/or fluid migration into a cemented annulus. Gas migration can occur when overbalance pressure across a gas and/or fluid bearing zone is lost. Overbalance pressure is lost due to the combined effect of fluid loss, gel strength development, and the compressibility of the cement slurry. Because foam cement is compressible (i.e. minimal pressure loss with a given amount of fluid loss) and has built-in fluid loss control, the loss of pressure in the annulus is minimized while the cement is setting up. This minimization of pressure loss aids in the prevention of annular gas and/or fluid invasion.

5.

Reduced Environmental Impact: Another potential benefit of utilizing foam cement is potentially a reduced environmental impact. Less cement and potentially fewer chemicals are needed to obtain and equivalent volume of cement slurry for a given job in comparison to when conventional lightweight cement systems are used. Reduction of these materials could mean less impact on the environment in manufacture, transportation, and utilization during the cementing operation.

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Strength (psi)

C lass G C em ent @ 100 °F 1200 1000 800 600 400 200 0 6 lb/gal 12 Hour

8 lb/gal 24 Hour

10 lb/gal 72 Hour

Figure 16: Compressive Strength of Some Foam Cements Using Particles to Increase Slurry Weight Additives used to increase slurry density need to have the following properties:

• have low water requirements (do not need much extra water to maintain • • •

the desired fluidity), exhibit no significant strength reduction (due to dilution of the cement per unit volume) have uniform particle size, or a particle size which does not sediment out be chemically inert or beneficial.

Hematite Hematite, an iron ore, is the most widely used slurry weighting material. Even though it has a relatively high specific gravity, (5.02), the small particle size of the ground additive helps keep it suspended in the cement slurry. Hematite high density slurries also contain some dispersant to maintain a good solids-suspending consistency without having to add much water to the formulation. Slurries weighing up to 20 lbs per gallon have been mixed and pumped with this additive.


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Figure 17: Hematite Slurries With Class H Cement Hematite Lbs./Sk

Water Gal./Sk.

Weight Lbs./Gal

Yield Cu. Ft./Sk.

0

4.29

16.47

1.05

10

4.50

17.00

1.11

20

4.60

7.68

1.16

30

4.66

18.15

1.20

40

4.75

18.70

1.24

50

4.81

19.15

1.28

60

4.90

19.60

1.33

Figure 18: Hematite + 35% silica flour Hematite Lbs./Sk.

Water Gal./Sk.

Weight Lbs./Gal

Yield Cu. Ft./Sk.

0

5.86

16.04

1.46

10

5.95

16.50

1.51

20

6.00

17.00

1.55

30

6.10

17.45

1.59

40

6.20

17.71

1.63

50

6.30

18.25

1.68

60

6.40

18.60

1.73

70

6.50

18.91

1.77

80

6.60

19.25

1.82

Barite Barite (barium sulfate) has been used for many years as a weighting material for drilling muds but has limited application in cementing slurries. While its specific gravity is high (4.23), the material has a fairly high water requirement due to its fineness. The additive requires about 22% water by weight. This complicates the design of the slurry since extra water lowers the density. The problem can be minimized by using dispersants. Slurry weights up to 19 lbs per gallon have been mixed and placed using barite.

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Manganese Oxide Recently, manganese oxide (hausmannite) has been used as a cement additive to help obtain high density slurries. The additive has an specific gravity of 4.9. The material is ground to an average particle size of 5 microns. Because of its fineness, the additive can be added directly to the cement mixing water, and it will remain in suspension. This property facilitates mixing of heavy slurries offshore, on the fly, without having to dry blend. Combinations of Hematite and Manganese Oxide have been used to design ultra heavy slurries at densities up to 23 lb/gal for ultra high pore pressure environments in some areas of Colombia. Adjusting the Slurry Rheology Dispersants are chemicals that are included in cement slurry formulations to improve fluidity. Dispersed slurries exhibit lower viscosities and therefore are easier to mix and can be pumped at lower pump pressures, thus lowering the horsepower needed for the job and reducing the chance of damaging weak zones (lost circulation). Dispersant are polymeric chemicals normally available in powdered form, although liquid forms are used offshore. Normal concentrations for dispersants are in the range of ~0.2% to ~1.5% based on the weight of the cement. In addition to lowering the viscosity, these products impart a low level of retardation to the cement slurries, particularly at low temperatures. Dispersants are included in slurries to be exposed to a wide range of temperatures, from low conditions (60F), to very high levels (350F). Often the dispersants are used mainly to allow mixing of the cement. In general, dispersants are compatible with most other additives, and can be used in many slurry formulations, with few problems. One exception is systems containing high concentrations of sodium chloride (above about 15%). With salted slurries, the dispersants may tend to initially thin the slurries, but after a few minutes, the slurry may flocculate, producing large increases in viscosity. One caution that must be observed with dispersants if to make sure the slurry is not over-dispersed. Excessive amounts of dispersants de-stabilize the slurry, causing large levels of free fluid and increased slurry settling tendencies. Adjusting the Slurry Thickening Time As previously indicated, the slurry thickening time is adjusted with the use of retarders or accelerators, depending on the well temperatures. Accelerators are normally inorganic chemicals that speed up the reactions of hydration of the cement. Since acceleration of the set time of cement slurries is normally not needed unless the well temperatures are low, these additives are normally not used at temperatures above about 100F. Slurry acceleration is usually needed for the cementing operations of conductor and/or surface pipe to Cement Slurry Design 3-49 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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reduce WOC time and rig time costs. The most commonly used and effective accelerator is Calcium Chloride. Many other inorganic materials can accelerate slightly. Sodium Chloride is a good example and seawater another. Retarders are usually organic chemicals that retard or slow down the reactions of hydration of cement systems. Extension of the set time is normally needed for the deeper casing strings. Retarder materials include lignosulfonates, some organic acids and sugar derivatives. Cellulose derivatives used to help control the fluid loss of cement slurries also perform as retarders at low to moderate temperatures. At elevated temperatures, lignosulfonate retarders are stabilized by the addition of borax. Controlling Slurry Fluid Loss Low fluid loss cement formulations have application in squeeze cementing operations, and during primary cementing across narrow annuli, under high differential pressures, and particularly for controlling gas migration after the cement job across gas and water zones. Many fluid loss additives are cellulose based. Because of this, they tend to increase the consistency of the slurry, and in addition, they also increase the thickening time of the formulation. The degree of retardation depends on the concentration of the additive, and the well temperatures. Often dispersants need to be added to adjust the fluidity of the system. Dispersants tend to enhance the effectiveness of cellulose base fluid loss control additives. Latex materials are also used to control fluid loss in cement slurries. . Imparting fluid loss control to slurries containing calcium chloride or sodium chloride for low temperature applications is a difficult task. Fortunately, there are some fluid loss control additives available that are compatible with sodium chloride up to a concentration of around 18% by weight of the mixing water. Controlling Slurry Stability Cement slurry stability is particularly critical in highly deviated, extended reach and horizontal wells, and in any situation with potential for gas/water migration after cementing. For these applications, designing for slurry stability becomes extremely important. The conventional way to control this slurry property is by designing the slurry with very low to zero free fluid with a rheology that facilitates mixing and placing. At the same time, the rheology needs to promote suspension of the solids at static and dynamic conditions, and under downhole temperatures and pressures. Conventional materials such as bentonite that can be used to help suspend solids but the industry has developed additives that do not increase viscosity at the surface – thus facilitating mixing - but that 'yield' under temperature, as the sluury is going downhole. Rev. 01/2002


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Using Loss Circulation Control Additives in Cement Slurries Losses of whole mud or cement slurry to natural or induced fractures or vugs during drilling or cementing operations are referred to as 'lost circulation' or 'lost returns'. Lost circulation should not be confused with filtration loss (seepage), which normally occurs due to pressure differential across the permeability (filtercake formation and dehydration through the filtercake). Lost circulation problems during drilling need to be solved before starting the cementing operation. However, it is not uncommon to again experience loses during the cement job, if weak zones are present. Minimization of these problems must be addressed during the planning of these jobs. Some materials that can be included in the cement slurry to help with the situation during cementing include:

• granular materials; • flakes; • fibrous materials Granular Materials To enhance their effectiveness, granular materials generally contain a distribution of particles ranging from coarse (1/4 in.) to a fine powder. The coarser particles bridge the fracture and the smaller particles then pack in around and over the larger particles to complete the shut-off. The most commonly used granular additive is Gilsonite. Another granular material available is ground walnut shells sold under the trade name "Tuf Plug". The shells are sold in three size grades: coarse, medium, and fine, and should be used in combination to again augment the efficiency of the additive. Normal concentrations of walnut shells used range from 1 to 5 lbs per sack of cement. A third lost circulation additive containing granular materials is sold under the name of 'Kwik Seal'. It contains fibers in addition to granular material and is also available in three grades, coarse, medium, and fine. Normal concentrations used in cement slurries range from 1 to 3 lb/sk. Higher of concentrations of 5+ lb/sk have been used in specific instances across depleted zones in Trinidad. As for all lost circulation materials, at the higher concentrations, it is important to make sure that the float equipment is not plugged by the additive and that mixing and surface equipment can cope.


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Flaked Materials The lost circulation control additive most commonly used in cement slurries is cellophane flakes. The flakes perform better when used across unconsolidated or highly permeable zones where the lost circulation material can plaster over the thief zone. The flakes are not as efficient across fractured zones as the granular or fibrous materials. Cellophane flakes are usually used in concentrations ranging from of 1/8 to 1/4 lb per sack of cement. Fibrous Material These lost circulation additives are usually short nylon or polypropylene fibers used in concentrations of 1/8 to 1/4 lb per sack. These materials are best suited to bridge off narrow fractures. Normally these additives are used in combination with granular or flake materials. Bulk handling of the dry cement with fiber added is troublesome, and special handling procedures for adding the fiber at the mixing tub are often needed. Fibers can also be used to keep the cement together in case it is damaged (cracked) downhole.

Effects of Extreme Temperatures Strength retrogression at temperatures above about 230 deg F is prevented by the addition to the slurry formulation of 35% fine crystalline silica (silica flour or silica sand). The silica actively enters into the reactions at these temperatures, generating reaction products that exhibit high strength. Silica is also added to slurries used to cement surface casing strings in HPHT wells. This is because during production the cement will be exposed to temperatures above 230F. Data indicates that strength retrogression is possible, depending on the temperature and recipe used, with cements that have set at low temperatures, but are later exposed to elevated temperatures above 230F. Special Situation - Deep, Long Liners The design of deep long liners is normally complicated by the extreme differential temperatures encountered from the bottom to the top of the liner. It is not uncommon to find situations where the circulating temperature at the bottom of the liner may be higher by as much as 50F or more than the static temperature at the top of the liner. In these situations, waiting on cement times may be extended in many cases to 48 and even 72 hours to allow the top of the column to set. In cases of extreme temperature differentials, stage tools have been used because it has not been possible to design a cement slurry capable of having the required thickening time at the BHCT, and also be capable of setting up in a reasonable time at the top of the liner. Rev. 01/2002


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Special Situation - Geothermal Wells Although geothermal wells are usually completed in the same manner as conventional oil and gas wells, the environment is more severe. The bottomhole temperature in geothermal wells can be as high as 700°F, and the formation brines are often extremely saline and corrosive. Many failures in geothermal fields have been directly attributed to cement failure. In geothermal wells, the temperatures always exceeds 230°F. Studies have shown that at least 35% silica flour is required to minimize strength retrogression. However, in geothermal wells where very high amounts of CO2 may be present, it has been suggested that reducing the silica flour concentration from 35% to 20% may improve cement resistance to CO2 attack. However, these formulations need to be carefully tested in the laboratory at the expected well conditions. At present, geothermal well cements are usually designed to provide a minimum of 1,000 psi compressive strength, and no more than 0.1 md water permeability in accordance with the API Task Group on Cements for Geothermal Wells, 1985. In addition, the set cement must also be resistant to degradation by saline brines. Based on extensive lab tests performed by Schlumberger on slurry designs under conditions similar to those in geothermal wells, the following guidelines were documented for slurries to meet the above requirements:

• Silica flour must be used to prevent strength retrogression at temperatures exceeding 230°F.

• Silica fume should be used in small amounts (<10% bwoc) to reduce permeability.

• The active solids-to-liquid ratio (by weight) should be 2.0:1 or greater. • Slurry density should be reduced using microspheres or by creating foamed cement with nitrogen.

• Foam quality should not exceed 30%. • Special CO2 resistant systems stabilized with silica can be used to obtain extremely low permeabilities and good strength.

• Latex slurries can be used to prevent gas migration as long as placement temperatures are below 350°F to 400°F.

• Class F fly ash must not be used above 400°F. • Microspheres, if used, must be composed of glass for BHST above 400°F. • Bentonite should not be used in CO2 environments. Cement Slurry Design 3-53 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Special Situation - Ultralow Temperatures (Permafrost Zones) Permafrost zones in areas such as Alaska and Northern Canada present some unique cementing difficulties. Permafrost is defined as any permanently frozen subsurface formation. Frozen formations extend to depths greater than 2000 ft and may consist of frozen soil in some areas or contain ice blocks in other areas. When permafrost exists, the cement system to be used should have a low heat of hydration to prevent thawing of the permafrost, must not freeze and be able to develop sufficient compressive strength at temperatures as low as 20°F. Conventional cement systems are not satisfactory in permafrost conditions because they freeze before developing sufficient compressive strength. Special cements such as gypsum/Portland blends with sodium chloride as a mix water freezing depressant, are used extensively for permafrost cementing. For surface pipe, these slurries are designed for 2 to 4 hours pumping time, yet their strength development is quite rapid and varies little at temperatures between 20 and 80F. A typical composition consists of a 50:50 blend with 12% salt. The gypsum sets and gains strength rapidly at freezing temperatures, and protects the slower setting Portland cement from freezing. These cements also have a low heat of hydration.

Other Special Conditions, Systems and Additives Salts (Sodium, Potassium) as Cement Additives The original use of salt (sodium chloride) in cements began in the late 1940s for cementing casing through salt formations in the Williston Basin of North Dakota, U.S.A. Collapsed casing was a repeated problem in that field until the cause was traced to flow of the salt formations. It was theorized that the cement slurries were leaching salt from the formations during and after placement, creating voids behind the pipe, facilitating the flow of the salt. It was expected than when a non-salted slurry was placed across a salt horizon, dissolution of the salt occurred at the cement/salt interface due to ion exchange, and poor zonal isolation resulted. This dissolution of salt formations has been confirmed with laboratory experiments. In contrast, excellent bonding at the interface cement/formation has been observed with salted slurries. In laboratory tests, shear bond strengths were measured at the interface using slurries with varying salt concentrations. The results showed that improved interface contact occurs with increasing salt concentrations in the cement. Although no dissolution occurs when a salt-saturated slurry is used, these slurries are quite difficult to design with the desired properties of compressive strength development, settling, free water, fluid loss, etc. For this reason, cement slurries used across salt formations often contain about 18% salt.

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This practice allows better control of the slurry properties, and has produced good results. In addition, many of the cement recipes are designed with potassium chloride instead of sodium chloride. Lower concentrations ( 3 to 5%) of KCl can be used with similar results, and KCl slurries are easier to design. The problem has also been helped by the development be the service companies of special polymers (for example Schlumberger's Saltbond). Another benefit of using a salted system across salt formations is that the design is relatively immune to effects of salt contamination during placement. In general, thickening times are reduced when cement slurries contain up to about 7 to 10% salt, essentially unchanged at concentrations up to about 18%, and then increase with increasing concentrations of salt. The time required to develop adequate compressive strength also generally increases with increasing salt concentrations. Because of this strength retardation effect, when designing slurries to be placed across fast moving salts, the overriding consideration is to design the slurry such that it will develop adequate compressive strength as fast as possible. Often in these fast moving salt situations, heavier/thicker casings are used, along with accelerated cement slurries, with minimum thickening times and lower safety factors, to get the cement to set fast, before the formations have time to contact the casing string, to minimize damage to the pipe. A few years after starting to use salt in slurries across salt formations, it was also observed that remedial squeeze cementing operations were improved (fewer squeeze stages required) when produced salt water was used for mixing cement in the western areas of the State of Texas, U.S.A. Investigators determined that the salt in the mix water was less disruptive and damaging to bentonitic sands and to shale beds, and produced a better cement bond to the shale. It was also observed that salt concentrations less than saturated, 10% to 18% based on weight of the mix water, were sufficient to protect freshwater sensitive formations. Later, 3% to 5% potassium chloride was found to be equally effective, and again these lower concentrations of KCl were less destructive to the effectiveness of the fluid loss control additives and facilitated the design of the slurry formulations. Finally, a word of caution. High concentrations of salt in cement slurries need to be used only when necessary (KCl is preferred over NaCl because of the lower concentrations and reduced negative effects). It has been shown that the use of salted cement slurries across fresh water formations can be very detrimental to the long term stability of the cement. Due to the differences in ion concentrations, dissolution/osmotic forces can eventually destroy the integrity of the cement.


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Detrimental Effect of Magnesium Salt Containing Formations Some salt formations contain very mixed salts and some contain Magnesium Chloride. The seriously detrimental effects of magnesium chloride on cement has been well documented. Magnesium chloride attacks calcium hydroxide (free lime) in the cement forming calcium chloride, and causes decay of the calcium-silicate-hydrate (C-S-H) structure of cement (formed during hydration) through leaching of the calcium by chloride ions. The cement is further weakened during the process by the formation of expansive compounds such as chloro-aluminates and brucite (magnesium hydroxide). The cement is therefore attacked both chemically and mechanically. It should also be noted that if the slurry becomes contaminated with magnesium chloride during placement, serious viscosity increases can occur and the thickening time of the slurry can be significantly reduced. This viscosification is caused by the precipitation of magnesium hydroxide. It has been noticed that contamination of cement slurries by less than 5% by weight of water (bwow) of magnesium chloride can reduce their thickening time by more than 50%. It has also been found that attack by magnesium chloride can be averted or minimized by:

• • • •

reducing the free lime of the cement, reducing the permeability of the set cement, and using cement systems that develop fast early strength using available cement formulations that resist attack by magnesium chloride

If magnesium brines are to be encountered in formations along the interval to be cemented, the best practice is to use a magnesium resistant system. In addition, compressive strengths and contamination tests should be performed on the slurry using a magnesium brine fluid medium, preferably taken from the field at hand. A high magnesium resistant (HMR) cement system is available to the industry. The HMR system uses a special blend of Portland cement and granulated blast furnace slag to which 28% fly ash and 15% salt (sodium chloride) are added. The blended product is mixed at a density of around 15.8-16.0 lb/gal. This cement was successfully used across 11,850 ft of massive salt in a Netherlands well in the Dutch North Sea where the presence of magnesium chloride was expected. Other available magnesium resistant systems incorporate latex and special polymers. Detrimental Effect of Sulfate Waters Formation brines containing sulfates are among the most destructive downhole agents to Portland cements. The deterioration is usually characterized by expansion, strength loss, cracking, and finally complete failure of the cement structure. Sulfate containing brines are found in West Texas and Kansas, U.S.A., the North Sea, and other oil producing area of the world. Rev. 01/2002


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The downhole brines which contain magnesium and sodium sulfates react with calcium hydroxide (precipitated during cement hydration) to form magnesium hydroxide, sodium hydroxide, and calcium sulfate. The formation of magnesium hydroxide (brucite) causes expansion as mentioned earlier. The formation of sodium hydroxide increases the porosity of the cement since it is more soluble than calcium hydroxide. The calcium sulfate reacts with aluminates (present in the cement) to form secondary ettringite, a tri-calcium aluminate (C3A) product which causes expansion. Large calcium sulfo-aluminate crystals are also formed. The calcium sulfo-aluminate crystal contains 31 molecules of water; thus, the product is a large molecule that requires more pore space than the set cement can provide, causing excessive expansion. The effect of all these reactions can be uncontrolled expansion leading to loss of compressive strength and eventual complete deterioration of the set cement Temperature influences the sulfate resistance of a hardened cement. From investigation conducted at both low and high temperatures, it was concluded that sulfate attack is most pronounced at temperatures between 80F to 120F. At temperatures of 180F and above, the attack is negligible. This conclusion is supported by observation of actual wells. Cement failures due to sulfate attack are more common in shallow wells where temperatures are lower than 200F. The API classifies cements as moderately sulfate resistant (MSR) and highly sulfate resistant (HSR) on the basis of the tricalcium aluminate (C3A) content. A MSR cement contains 3-6 weight % C3A; and a HSR one 0-3 weight % C3A. API HSR cements , are less susceptible to sulfate attack after setting, and should be used whenever downhole brines may exist which contain magnesium and sodium sulfates. Sulfate attack can also be substantially reduced by the addition of pozzolanic materials, such as fly ash, to the cement system. Effect of CO2 Carbon Dioxide Laboratory and field studies have shown that carbon dioxide in the presence of moisture, can destroy the structural integrity of set Portland cements. The reaction involves the formation of carbonic acid which attacks the alkaline constituents (Ca(OHfavouredcium carbonate into soluble calcium bicarbonate. This begins a chain reaction. The dissolved calcium bicarbonate reacts with the alkaline constituents forming calcium carbonate and water. The water dissolves more calcium bicarbonate. The net result is a “leaching” of cementitious material from the cement matrix, increasing its porosity and permeability and decreasing its compressive strength. Downhole, this can result in a loss of casing corrosion protection and a loss of zonal isolation. Cement Slurry Design 3-57 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Carbon dioxide corrosion of Portland cements is thermodynamically favored, and therefore, cannot be completely prevented as long as Portland cement is used. For economic reasons, the approach which has been generally adopted is to slow down the rate of degradation of portend cement by a combination of the following means: • Addition of a pozzolanic material (fly ash) to the cement to reduce the alkaline constituents (free lime) available for reaction, and to reduce permeability. • Lowering of the water-to-cement ratio (densification) to reduce cement matrix permeability. • Addition of latex for additional sealing effectiveness • Use of CO2 resistant cement blends For example, a cement slurry design for this application may utilize a 50:50 type C poz -Class H blend, and 2 gals of latex per sack of blend, mixed at 16.4 lb/gal. Special CO2 resistant cement blends are also available. For example D889 developed by Schlumberger. The developers claim that the blend, when mixed at a cement-to-water ratio of 2.3 to 1 or greater, provides 45% more resistance to the action of CO2 leaching in cements than either neat class H cement or type F fly ash/cement admixtures of equivalent slurry density. Another system developed by Halliburton is claimed to produce significantly better corrosion resistance to CO2 than the previously used systems, particularly when wells are subjected to acid treatments. This claim is based on field tests performed on samples installed in actual CO2 injection wells. This system called Flexcem is significantly more expensive than conventional systems. The product uses a crosslinked latex as its primary constituent, to which a quick-setting non-Portland cement (25% by weight of latex), and silica flour (125% by weight of latex) are added to provide structural rigidity. Base systems are mixed at around 9 lb/gal and have been weighted to around 12 lb/gal. The developers claim that the properties of the system such as thickening time, compressive strength, etc., are repeatable under standard API laboratory conditions. Thixotropic Cements Thixotropic slurries are systems that have low viscosity while being sheared (pumped) but build high gel strength very rapidly when shearing (pumping) stops. Upon resumed pumping, the slurries should ideally revert back to their initial low viscosities, and this behavior should be repeatable for several cycles. Unfortunately thixotropic slurries that truly behave as described are hard to design. They tend to gel fast, but may not gel and thin through several cycles as it may be desirable in some applications. In addition, they in general have limited temperature applications and their 'thixotropic' properties can be negatively affected by several cement additives, again limiting the applicability of these slurries. Rev. 01/2002


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In the real world, under downhole conditions, the best that can be hoped for is for the slurries to develop high levels of gel strength once pumping is stopped. The true gel strength properties of these systems need to be measured, at downhole conditions of temperature and pressure, using devices such as the MACS or the retrofitted UCA. The primary advantages of thixotropic slurries are:

• Improving fill-up by reducing loss of slurry into weak formation, vugs, caverns, etc.

• Quick-gelling to inhibit gas movement through the slurry. • Expanding properties One way to produce a 'thixotropic' slurry is to blend gypsum hemihydrate with an API Class A, G, or H cement at concentrations of 8 to 15 percent by weight of the cement. Other more sophisticated formulations are also available from the service companies. Many of the applications of thixotropic slurries are at low temperatures, but uses of the systems have been reported to temperatures as high as 260F.

Deepwater Situations We already reviewed under Special Considerations, the complicating factors associated with cementing operations in deepwater locations. Here we will review slurry design considerations for this type of application. The main emphasis as can be expected is on the slurries used to cement the shallow casing strings, particularly if the potential for shallow water flows exist. Once these strings are successfully cemented, design of the slurries for cementing of the deeper casings can be handled similarly as for land operations. The following are the requirements for cement slurries to be used to cement the shallow (conductor, surface) strings in deepwater applications.

• • • • • • •

Maintain hydrostatic pressure control Exhibit short transition time Capable of setting fast at low temperatures Capable of developing adequate compressive strength Contribute to good displacement efficiency Flexible to allow design modification Provide long term sealing -

Good bonding

-

Ductility

• Have good fluid loss and free fluid control Cement Slurry Design 3-59 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Both conventional and foam cement systems are available to cement the shallow strings. However, after carefully examining the list above, it is easy to see why foam cement slurries are used most of the time when potential for shallow water flows exist. Foam systems present the following advantages over conventional systems:

• • • • • • •

Excellent sweeping (displacement) properties Very flexible system (easy to adjust densities on location) Superior compressive strength at low densities and at low temperatures Good sealing properties (ductility) Inherent good fluid loss and free fluid control Excellent cement column pore pressure maintenance while setting Excellent flow after cementing control properties

For deepwater applications, one advantage that the conventional systems have over the foam formulations is cost. Cementing Slurries for Situations of Gas/Water Migration After Cementing

Guidelines for Selecting Flow Migration Control Slurries The following are general design guidelines for cement slurries to be used across hole intervals that present potential for fluid migration after the job: 1.

Transition Time. Transition Time needs to be short. We define Transition Time as the lapse of time from when the cement becomes static in the annulus (job time) to when gel strength develops to some figure, typically 500 or 1,000+ lb/100 ft2. The gel strength has to be measured under downhole conditions of temperature and pressure.

Note: Transition time cannot be obtained from the consistometer thickening time curve. Transition time needs to be measured using an apparatus like the MACS or the retrofitted UCA, under static conditions, and at downhole temperatures and pressures. It is normally accepted that if gas can be prevented from invading the cement during the transition period, the chances of severe gas migration problems in the well can be substantially reduced. Short transition times are desirable. As a rule of thumb, less than ½ hr. transition time is considered a short transition time. 2.

Non-settling/solids segregation. The cement column must be homogeneous from top to bottom. Settling/segregation can cause severe changes in the hydrostatic head particularly in a deviated well and cannot be tolerated. Free fluid. Free fluid must be zero and should be measured under downhole conditions of temperature and pressure.

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3.

Fluid loss. Fluid loss must be low. The lower the better. Without good fluid loss control, chances of controlling cement column invasion are very poor. "If nothing can leave the matrix of the cement, nothing can get in.” From successful field applications, less than 50 mil API (less than 20 mil API preferred) is the recommended design criteria across zones with flow invasion tendencies. The fluid loss must be measured under downhole conditions.

4.

Thickening time. TT must not be excessive. Cement behind the pipe needs to set up as soon as possible after the cement job. Leaving unset cement behind the pipe for extended periods of time is an invitation for potential problems. Thickening times should be designed whenever possible for the job placement time plus a reasonable safety factor (1 to 1-1/2 hr.).

5.

Laboratory testing. The gas migration control properties of the cement slurry should be tested in the laboratory under simulated downhole conditions. An industry available procedure called the Scale-Down will be discussed below. The use of the Halliburton “flow potential” concept represents a good effort in the right direction and should be used as a “screening tool,” but exclusive use of this and other selection criteria fall short of the necessity of actually testing in the laboratory, the selected recipes under simulated downhole conditions before the final selection is made. In cases where gas invasion/migration is a serious concern, testing a cement formulation for gas migration control in the laboratory should be considered as important as testing the thickening time and compressive strength of the recipe.

Scale-Down Laboratory Test Method A detailed description of the Scale-Down method is outside the scope of this manual. Thus, only a brief overview of the method is given below. A special lab device is used to conduct the gas migration test under the simulated (scaled-down) well conditions. The Scale-Down lab procedure addresses a “worst case” scenario. The method assumes that the offending gas zone (source of the invading gas) has enough permeability, thickness and gas volume to fully invade and pressure-charge the cemented annulus (cement column), if conditions allow it. In the laboratory procedure, the measured, actual gel strength development of the slurry is used to estimate the maximum potential pressure decline in the cement column. The calculated pressure decline schedule is then used to allow dehydration from the cement into the simulated gas formation, and to predict when a pressure differential needs to be applied across the slurry to potentially drive gas/water through the sample. The magnitude of the pressure differential placed across the cement specimen is calculated using Darcy's Law, assuming that equal “bulk permeabilities” exist in the well and in the test cell. The gas influx into the cement is measured . Cement Slurry Design 3-61 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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At the end of the test, it is possible to tell if the proposed slurry formulation will control the gas migration problem in the given well across the zone of interest. Several service companies and independent laboratories have gas flow cells, and thus can conduct Scale-Down tests.

Figure 19: Scale Down Test Device

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Cement Sampling, Blending and Quality Control Dry Cement Aim: Present field-proven cement sampling, blending and quality control procedures Recognise the importance of accurate sampling and protection of samples for lab testing

Introduction A knowledge of sampling and blending techniques and quality assurance issues with cements is vital to avoiding serious cementing problems. These techniques are needed to ensure that the cement slurries pumped down-hole closely match the cement slurries as designed in the laboratory. In many on-shore areas of the world, dry blending of the cement with dry additives is the method of choice. Most off-shore operations will use liquid additives and neat cement. However, even off-shore, there is often a blend of cement used at some stage of the well, e.g. Class G +35% silica. The methods described here are the result of many years of accumulated industry experience. Sampling of materials to Use for Pilot Testing The absolute necessity of conducting all the slurry design testing using the exact materials (cement, additives, field water) to be used in the actual cement job cannot be overemphasized. In order to have representative samples of the cement and additives to be pumped downhole, good sampling techniques need to be used. A sample of the field water needs to be collected in clean, sealed containers, properly marked and taken to the laboratory as soon as the source of water is secured at the well location. If the water is in a tank at the rig, the sample needs to be taken from a valve, after flushing enough water from the line to make sure the sample is representative of the water in the tank. However, if there are settled particles at the bottom of the tank, and the discharge line is close to the bottom, the sample should be taken from the top, dipping the sampler container into the water to try to collect the sample from the center of the tank. Cement Sampling, Blending and Quality Control 3-63 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The additive lots to be used need to be put aside for the job. Under no circumstances should several lots of an additive be mixed for the job. The same consideration applies for cement manufacturing runs. Samples of the additives for lab testing need to be taken from the lots to be used, from un-opened, undamaged bags. The materials need to be placed in clean bottles or containers and sealed. Bulk cement sampling can be done using devices shown in the Figure below, taken from API Spec-10B. Silos may be equipped with one of the sampling devices shown below. Lines need to be purged long enough before taking the cement sample to make sure the sample is representative of the cement in the tank and not just what is trapped in the line. If the cement is in a transport equipped with an upper hatch, samples can be taken using a special tube (auger) that allows small samples to be taken simultaneously, at different depths, when pushed into the cement from the top. The same techniques and devices can be used to sample cement blends from tanks and silos. Pilot testing by the lab will establish a suitable slurry design on which dry blending will proceed. Once blended, the cement blend will have to be confirmed by repeating the lab tests and assessing any variation. Cement is a very reactive material and will chemically react with moisture in the air. This will change physical properties like thickening time and compressive strength development. The extent to which this happens can vary widely. Some cements are particularly sensitive, others not so. In any case, small quantities, e.g. a cement sample, are particularly vulnerable to exposure and, if not adequately protected, exposure of just a few hours can make several hours difference to the thickening time – generally lengthening it…. the consequences of testing such a samples and designing the retarder concentration can be disastrous! The following guidelines should be adhered to:

• Cement container: -

Large enough for 5 kg, 10 lbs minimum

-

Air-tight, waterproof and strong enough to remain so during transit

-

Clean, dry and preferably un-used

-

Completely filled to exclude as much air as possible

-

Lined with a clean, previously unused, polythene bag

-

Labeled to show the cement silo number, date, location, cement type and blend, sample method.

Note: it is better to label the body of the container, not the lid.

• Additive containers

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-

Clean plastic bottles, 0.5 litre, 1 pint, or larger

-

Water tight lids, sealed with tape to prevent unscrewing in transit Cement Sampling, Blending and Quality Control 3-64 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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-

Labeled to show location, date, source (LAS, bags, etc), additive name, lot number, etc

Note: roll drums, or circulate LAS, to ensure active components of liquid additives are in suspension

• Mix water container -

Clean plastic bottle 3-4 litre, 1 gal, or larger

-

Water tight cap sealed with tape

-

Labeled to show date, location, type (sea or drill water). Do not use soft drink bottles. Figure 20: Bulk Sampling Devices

Cement Sampling, Blending and Quality Control 3-65 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Steps for Successful Cement Blending The following are the logical steps that lead to a successful blending operation. For critical jobs, it is not uncommon for a oil company representative to witness the entire blending operation. Step 1. Safety

Meeting

Step 2. Isolation

of all materials to be used

Step 3. Planning

Meeting to discuss the entire blending operation, and to make the final blending calculations

Step 4. Inspection

of bulk and blending equipment

Step 5. Calibration

of blending equipment, as needed

Step 6. Blending Step 7. Sampling

of the cement and additives of the blends

Step 8. Confirmation

testing

Isolation of Materials to be Used in the Job As soon as the slurry design to be used is identified, a conservative estimate of the job size (slurry volume) should be made. Dry, liquid additives and cement in sufficient quantities to cover contingencies such as greater than anticipated hole enlargement, etc, should then be secured in a clearly identified area. The materials are often isolated several days before the actual blending operation. Planning Meeting Influence of the Well Location A clear understanding of the size and configuration of the well location, the condition of access roads (or marine transportation) is needed. This initial part of the planning meeting may include a review of a diagram of the well location showing the position of all the major components. Selection of the Equipment The next item of discussion is the selection of the equipment to be used (transports, batch-mixer, pumps, etc.). To be able to make a good selection, it is necessary to know the capacity and capability of the transports, the batch-mixers and pumping equipment. This information affects how the blends will be transported to location, stored while waiting for the job, and finally mixed and pumped. Whenever possible, critical liner slurries should be batch-mixed. Rev. 01/2002


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Final calculations of the slurry volumes and bulk blend volumes need to be made, to help finalize the selection of the equipment (size and number of transports, etc.). It is a good idea at this point to add to the location diagram, the position (spotting) of the different pieces of equipment. to be used. Bulk Plant Considerations Locations throughout the world vary in layout, capacity and capabilities. For example, does the bulk plant have a scale tank and a blending tank, or is it equipped with only a scale tank? This is very important because the blending practice that consists of loading the cement and additives into the scale tank and percolating air through the blend does not completely blend the cement and should not be used alone. This practice is particularly ineffective when materials like sand, hematite, salt and silica flour are part of the cement formulation. Air percolating may actually de-blend the mixture, with the heavy and the larger particles ending up at the bottom of the batch. To properly blend cement, the blend must be pneumatically transferred a minimum of three times before it leaves the service company yard. So, if the plant is equipped with only the scale tank, it may be necessary to hook up a clean transport to the bulk plant, to use it as a blend tank. Often the use of a transport as a blend tank considerably extends the length of time that it takes to blend, due to the difficulty of moving the cement blend from the transport back into the scale tank while blending the cement recipe. This must be done, particularly for critical jobs. Percolation of air through the blend should only be used as part of the blending operation, and with some bulk plant configurations can be substituted for one of the moves (transfers) as will be seen below.


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Figure 21: Pneumatic Bulk Plant Selection of the Blending Procedure Blending methods are discussed below in order of effectiveness. 1)

Four pneumatic transfers: The cement blend is transferred from the scale tank to the blend tank, from the blend tank to the scale tank, from the scale tank back to the blend tank, and from there to the bulk transport. Notice that the transfer to the bulk transport is counted as a transfer. Experiments have shown that this number of transfers generates a good blend. Some in the industry prefer moving the cement six times.

2)

Three pneumatic transfers: The cement blend is transferred from the scale tank to the blend tank, from the blend tank to the scale tank, and from there to the transport. Some plants are constructed in such a way that the four transfers described above cannot be performed (cannot transfer from the blend tank to the transport), forcing the use of the 3 transfer method.

3)

Equivalent to three pneumatic transfers: The cement is percolated with air for 10 to 15 minutes in the scale tank. From there it is transferred to the blend tank, and then to the transport. If this procedure is used, the percolating pressure should not exceed 10-15 psig in order to minimize gravity segregation within the blend. Notice that the percolation is counted as one transfer.

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4)

Some locations throughout the world like to move the blend only twice before it leaves the yard, and count on the last transfer on location, from the transport to the batch or recirculating mixer to complete the blending operation. This practice is not recommended. The cement blends should leave the service company location fully blended. In addition, if this practice is used, the operations of sampling of the blend and confirmation testing will be negatively affected. Sampling and confirmation testing will be discussed later on in this section.

Blend Size The blending of the decided amount of cement formulation is done in "batches" at the bulk plant. The selection of the size of the batches is affected by the capacity of both, the scale tank and the blending tank. It has been found that the if the tanks are over-filled, then the effectiveness of the blending operation is negatively affected. To properly blend the cement recipe, the bulk volume of each batch should not exceed about 40% of the capacity of the smaller of the scale and the blend tanks. This is to allow plenty of empty space in the tanks for the cement blend to move freely and blend as it is being transferred from tank to tank. If needed, the batch size can be increased to up to 50% of the capacity of the smallest of the tanks, but this is not a good practice if the blend contains large particle additives such as silica sand, calcium chloride, hematite, salt, etc. When large particle materials are present, the 40% number mentioned above is the recommended batch size.


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Dry Blending Calculations Important Note: It is a good practice to make sure that all the calculations needed for the proper design of a blending operation be performed by two persons, independently of each other, and then compared, to minimize human error. The dry bulk yield of a formulation is the sum of contribution of all the dry components of the recipe. This yield is determined from a material balance using the bulk densities and the concentration of the dry additives being used. The dry bulk yield of the given cement recipe is needed in order to properly size the batch to be blended. An example of these calculations is given below. Figure 22: Dry Bulk Yield of a Cement Formulation Material

Concentration (BWOC)

Weight (lbs)

Bulk Density (lbs/cu.ft.)

Bulk Yield (cu..ft..)

Cement

100%

94.00

94

1.00

Silica flour

35%

32.90

70

0.47

Hematite

50%

47.00

193

0.24

Dry retarder

0.5%

0.47

36

0.01

Dispersant

0.5%

0.47

36

0.01

Dry bulk yield (cu.ft./sk.) = 1.73

For the example case given in the Table, the calculated dry bulk yield of the particular recipe is 1.73 cu.ft./sk. So, for a blend of the cement recipe of say 450 sacks, the total dry volume would be 778.5 cu.ft. The number and size of the batches which will be required are determined, based as indicated before, on the need to stay at 40% of the capacity of the smallest of the scale and blend tanks. If for example the capacity of the smallest tank was 280 cu.ft., then the maximum batch size would be 112 cu.ft., and seven batches would be required to blend the 450 sacks of the cement recipe. Following, the weight of the cement and additives to be used in each batch are determined based on the concentrations of the recipe and the pre-selected size of the batch. A blending schedule is prepared. In the schedule, half of the cement is added first, followed by all the additives which are then "sandwiched" by the second half of the cement. This sandwiching approach has been proven effective in numerous blending applications. Some in the industry like to use several layers: cement, additives, cement, etc. This is time consuming and, in general, does not generate better results than the single layer approach. Rev. 01/2002


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Liquid Blending Calculations if a batch Mixer is Used The discussion below applies to the case that a batch mixer is going to be used, and the mixing liquid will be placed in the mixer before blowing into it the dry cement blend, to mix the cement slurry. When liquid additives are to be blended into the mix-water (batch approach), the amount of mix-liquid to be used for each batch (tank) of slurry is calculated using the mix-liquid requirements of the given slurry. As an example, let's assume that the usable capacity of each batch-mixer tank is 45 bbls, the slurry yield is 1.63 cu.ft./sk, and that the mix-liquid requirement for the slurry is 5.90 gal/sk. Let's also assume that four batches of slurry are going to be mixed in each of four batch-mixer tanks. We will also assume that four dry batches of 112.50 "sacks" were blended and transported to location in separate bulk tanks. Therefore the mix-liquid required for each blend is 15.80 bbls ((112.5 sk x 5.90 gal/sk)/42). The volume of slurry mix in each tank is 32.66 bbls ((112.5 sk x 1.63 cu.ft./sk)/5.6156) which is well within the capacity of the batch-mixer tanks. Once the volume of total mix-liquid per tank is determined, the volumes of each liquid additive required needs to be determined from the known concentrations. The Table below shows the calculation of volumes needed for the example case. Figure 23: Liquid Additive Volume Needed for the Example Batch Material

Concentration (gal/sk)

Total volume per batch (gal)

Latex

3.5

393.75

Stabilizer

0.35

39.38

Antifoamer

0.05

5.63

Liquid Retarder

0.5

56.25

Water

1.50

168.75

Total mix liquid volume 663.76 gal = 15.8 bbls

Inspection of Bulk and Blending Equipment to be Used in the Operation Bulk Equipment After the completion of the kick-off & safety meeting, the next thing is to inspect the equipment to be used. The main reason for this is to ensure that the equipment is functional and free of materials (old cement blends, etc) that could contaminate. Once inspected, this equipment must not be used in other jobs until after the blending at hand is performed. Cement Sampling, Blending and Quality Control 3-71 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Transports hatches must be opened and the inside of each tank inspected to make sure it is completely clean. Clean equipment, free of possible contaminants, is a ‘must’ to achieve a successful blending operation. Blending Equipment (Bulk Plant) General Inspection Blending procedures need to be discussed in detail with the bulk plant operator. Sandwiching of additives, number of transfers of the blend, sampling methods, etc, need to be discussed and agreed. It is not uncommon to find that following quality controlled blending procedures like the ones discussed here often takes longer than other less rigorous methods. However, the methods suggested should produce quality blends closely matching the slurry formulations designed in the laboratory. It is important to become familiar with the location of the scale tank, blend tank, bulk equipment tanks, lines, valves, etc. A free-hand diagram drawn with the assistance of the bulk plant operator will help in understanding of the equipment layout. It is important to question when any load devices were last inspected and calibrated. At this poin verify that the additives to be used in the blending operation have the same lot numbers that were used to run the pilot tests. This is a critical point during the bulk plant inspection. It might not be possible to confirm the lot numbers of bulk materials such as hematite, silica sand, etc, but many of the critical additives such as retarders, fluid loss additives, etc. have lot numbers stamped on the bags. If the additives are not of the same lot numbers, the blending operation should not start until a repeat of the pilot testing is done with the actual materials to be used to blend the cement formulations. Cleaning of the Blending Equipment It is imperative that the scale tank, the blend tank, the additives hopper and all the lines (from the bulk storage tanks and exiting the scale and blend tanks and the hopper) be completely clean of potentially contaminating materials. In the same way, the "socks" (dust collectors) often installed on top of the scale tank need to be free from all material possibly accumulated in them from previous jobs. The cleaning procedure needs to be performed prior to commencing the blending operation and it is carried out as follows: All the lines are purged into the scale and blend tanks several times. The socks are then shaken for several minutes to allow discharge of materials into the scale and blend tanks. The scale and blend tanks are then purged with air (30+ psig) into a discharge tank. The operation is repeated three or four times or until there is only dust coming out of the discharge lines of the scale and blend tanks. Rev. 01/2002


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With very dirty bulk plants (sometimes found in more remote locations of the world), or in situations were it seems that the plant is not "coming clean", 10 sacks (about 1,000 lbs) of silica sand can be run through the lines and tanks to help scrub the walls. After the sand, the cleaning operation outlined above needs to be repeated from the first step. Some scale and blend tanks are equipped with hatches that can be opened to inspect the inside of the tanks. When available, they need to be opened to confirm cleanliness at the end of the cleaning operation. Some plants have socks on top of the scale and the blend tanks. Others only have one set of socks. In any case, sometimes the socks are found to be non-operational. Every effort must be made to fix these devices before the start of the blending operation. Socks are used as dust collectors, but they are also very useful in putting back into the blend, the fine particles that tend to be carried out by the air during the blending operation. Non-operating socks prevent the operator from restoring the fine particles back into the blend, by periodically "shaking the socks" while blending. At the end of the cleaning operation, the bulk plant (scale, and blend tanks, hopper and all the lines) must be completely empty of materials from previous operations. Blending Equipment Calibration As previously indicated, it is important to note the last time the scales were calibrated by a calibrating entity. A certification should be available for inspection. Scales that have not been calibrated at least once in the last year can possibly be out of calibration and need to be checked. The following "quick and dirty" test of the accuracy the scale tank can be run before a blending operation starts: after zeroing the scale of the scale tank, two or three people of known weight climb on the scale tank (on top or on the frame) and a weight reading is taken on the scale tank. The weight recorded on the scale should be within 10 to 20 pounds of the sum of the weights of the individuals on the tank. If safety considerations, or doubt about the weight of the individuals, prohibit this ”quick and dirty" calibration approach, 5 to 10 bags of silica sand or barite on top of the tank can be used for the same purpose. Again, the reading of the scale should be within 10 to 20 pounds of the actual weight. If an error greater than 20 pounds is measured, the amount of weight in the tank should be varied (above and below the original weight used), and the scale read again. This should allow a determination if the error is constant or if it varies with changing weights. This procedure should be repeated several times, looking to see if a reliable, consistent and repeatable calibration trend line can be developed. If a calibration line cannot be developed for the scale tank, the blending operation should be suspended until the problem is fixed by the service company. Similarly, the additives scale needs to be checked using a known weight. Several sacks of additives of "known" weight (one bag at the time) can be used to check Cement Sampling, Blending and Quality Control 3-73 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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this scale, or any other available material of known weight can be used. The additives scale must be within a 1/4 of a pound or less of the known weight. It is recommended that the additives scale be calibrated before the scale tank. By doing this, the additives scale can be used to weigh the individuals or sacks of additives to be used to help calibrate the scale tank. Zeroing of the Scale Tank Another critical step in the process of proper blending of cement is the correct zeroing of the scale tank. Zeroing means exactly that. It means to force the scale tank to read "zero weight" at the start of a blending operation. The bulk plant operator makes the scale tank read "zero" by turning a knob on a beam type scale, or by pressing the zeroing button on an electronic read-out scale. Once the scale is zeroed, this same zero must be maintained during the blending operation. In addition, every time a weight is taken (read) on the scale tank, the same set of conditions present when the scale was originally zeroed must be repeated or the weight read will be in error. This set of conditions are the following: 1)

All the lines leading to the scale tank must be purged and therefore completely free of materials. When the tank is zeroed or when a weight reading is taking during the blending operation, the goal is to read the weight of the materials in the tank. So, the lines must be free of materials for two reasons. The first one is that if material is left in the lines, the weight of this extra material is not fully recorded when a weight reading is made. This material left in the lines will then be pushed into the tank the next time the line is pressurized. This can easily add several hundred extra pounds of the material present in the lines to the scale tank. The second reason is that lines full of material, because of the way they are connected to the scale tank, can add an undetermined amount of stress to the tank, causing the load cell on the tank to record a certain (undetermined) amount of extra weight over the true weight in the tank.

2)

The scale tank must be under a preset vacuum level, a preset pressure level or under atmospheric conditions (no pressure or vacuum). Some operators, to help facilitate the blending operation, prefer to zero the scale tank and make weight readings either under vacuum or with pressure in the tank. This has to do with the way the particular plant operates. For example, if materials are "sucked" into the tank by pulling a vacuum in the tank (say 10 inches of vacuum), the operator might prefer to read how much material is in the scale with vacuum in the tank. On the other hand, when transferring material out of the tank, it might be easier to read the weight in the tank with pressure (say 30 psig) in the tank. Either method is acceptable but again, once the scale is zeroed under a given set of conditions (vacuum or pressure), the same amount of vacuum or pressure needs to be present in the tank when a weight reading is made, or the reading will be in error.

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The best method is to zero the scale tank, and to make all weight readings at atmospheric conditions (with no vacuum or pressure in the tank). This is the most accurate and trouble-free way to know the weight of materials in the tank. This method should be the one used, unless the particular plant design prohibits its application. Some plant operators resist this method due to the extra time required to bleed the pressure or release the vacuum from the tank before taking each weight reading. Proper zeroing and weight reading of the scale tank is so critical to the blending operation that its importance cannot be overemphasized. For example: If the scale tank has been zeroed at atmospheric conditions, and a weight reading is taken either under vacuum or with pressure in the tank, the weight read can be several hundred pounds below or above the true weight in the tank, depending among other reasons, on the way the tank is plumbed. Dry Blending of Cement and Spacer Recipes Just prior to starting blending, it is recommended to drain the moisture sump of the air compressor to reduce the chance of moisture contacting the blend. This is particularly important in high humidity areas of the world. In high humidity areas, purging of the water in the compressor should be done several times during the blending operation. Important note: Even after draining the moisture from the system, highly hygroscopic additives may tend to absorb water from the air and therefore cause problems during blending. With these materials, the particles may tend to ball-up, and/or stick to the tank and line walls. Because of this, it is better to add highly hygroscopic materials (e.g. calcium chloride), particularly in areas of high humidity (for example Trinidad), to the mix-water whenever possible. Highly hygroscopic materials dissolve rather easily and in this way, it is ensured that the material will be present in the slurry formulation when pumped downhole. It is recommended that this procedure (adding the material to the mix-water) be used also during the pilot testing of the slurry. During blending, approximately 10 inches of vacuum are used to "pull" material into the scale tank. The storage tanks holding the bulk materials generally can be pressurized to help in transferring materials to the scale tank. The general procedure is to introduce first into the scale tank, half of the required cement. This is followed by other "bulk" additives such as silica flour and hematite. Next, the "sacked" additives are introduced through the additives hopper. This is then followed by the rest of the needed cement. Each time the operator needs to strive to get a weight on the scale tank, that is as close as possible to the cumulative weight target. The "socks" must be shaken regularly during the blending operation to minimize accumulation of materials in them. The maximum acceptable deviation between the actual cumulative weight read on the scale tank and the target weight should be about 50 lbs. It is industry experiCement Sampling, Blending and Quality Control 3-75 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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ence that trained operators, when required, can stay within this window. One common reason that causes many operators not to be able to accurately transfer materials into the scale tank, is not properly accounting for the material in the lines between either the bulk storage tank or additives hopper and the scale tank. An estimate of the weight of material which the lines will hold must be made before commencing blending (the bulk plant operator normally has a good "feel" for this weight). This will allow the operator to "fine tune" his operation so that a weight as close as possible to the target value is obtained for the material being introduced into the tank. Since the lines are full of material while transferring into the scale tank, the operator needs to aim for less than the target weight by the estimated weight of material in the lines. He must then shut off the valve feeding material from the bulk storage tank into the line, and purge the material in the lines into the scale tank. This purging of the lines may have to be repeated if it is suspected that material remained in "dead" spots of the lines. This can occur between shutoff valves and line sections which are not in the direct path of flow. After ensuring that all of the material has been introduced into the scale tank, the reading of the weight in the scale tank must be made under the same conditions as the "zero" reading (see Scale Tank Zeroing). The procedure described above needs to be repeated for each of the materials introduced into the blend. It should be noted that density differences between materials can significantly alter the weight of material in the lines. The operator must therefore not assume that the same "adjustment" can be made for the different materials being blended. If during a given transfer operation the operator does not bring into the scale tank enough of a given additive, causing the scale tank to read more than 50 lbs below the target weight, he needs to bring more additive into the scale tank. If on the other hand, he transfers too much of a given additive (more than 50 lbs over the target cumulative weight), proportional additions of the other additives and cement may need to be made at the end of the transfer operation to keep the correct proportion of components in the blend. Another common area where errors are made in dry blending is in not accounting for the weight of the sacks or bags when adding sacked additives at the hopper. Each bag of additive should be individually weighted, and the empty sacks should also be weighted to determine the rest of additive that is needed. Sacks usually weigh around 1 lb. Therefore for a 50-lb sack of additive, an error of about 2% can be introduced into the operation by neglecting to account for the weight of the sack. Small amounts of additive must be weighted into a clean container, and the weight of the bucket itself must be accounted for. When introducing additives through the hopper, the sacks must be carefully inspected to ensure that no "rocks" of material are present and that the materials have not absorbed moisture or have otherwise become contaminated. If any doubt exists, the particular bag of material should not be used. Large "chunks" of Rev. 01/2002


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additives might not break during blending. If small "lumps" are observed in the material being introduced into the hopper, these must be " broken-up" before being included in the blend. Some service company locations use a screen over the hopper to reduce the chance of adding large lumps into the tank. In addition, previously opened sacks of additives must not be used. When all of the materials have been introduced into the scale tank, the pressure in the tank should be increased to around 30 psig to perform the first transfer. If extremely light additives are being used to blend "light-weight" cements, for example ceramic "bubbles", the transfer pressure should be reduced to about 6-8 psig in order to minimize blend segregation and large losses of these light additives through the vents. In many cases this pressure is sufficient to transfer these light-weight blends at rates similar to those of the heavier blends. In all cases, during the transfer process, the "socks" must be shaken regularly to restore the light additives back into the blend. After each transfer process, the scale tank must be "pressured-up" and "blown-down" several times to maximize the amount of material transferred. It is normal to end up with 50 to 100 lbs of weight in the scale tank, even after several "blow- downs". This is likely caused by material that remains stuck to the walls, socks, etc. After the first transfer of the blend into the blend tank, the blend is normally "pulled" back into the scale tank, returned to the blend tank and finally transferred to the "transport". After the final transfer has been made from the scale tank, after several "blow-downs", and after the pressure in the tank has been bled down to atmospheric, the weight of material left in the scale tank needs to be recorded. This weight will need to be added to the actual cumulative weights of the next batch of blended materials. During the actual blending process, the "target" and actual cumulative weights should be documented and compared after each addition of additive or cement to the blend. This information is very important not only in "keeping track" of the weights added but also in ensuring quality control at each stage of the operation. The "target" cumulative weight for any particular additive is determined by adding the theoretical weight of the additive to the actual cumulative weight present in the scale tank (recorded after introducing the previous additive to the blend). Since scale tanks normally can only read weight in increments of ten (10) pounds, target cumulative weights are rounded off to the nearest multiple of 10 lbs. As mentioned before, The maximum acceptable deviation between the target and the actual cumulative weight after each addition of bulk material to the blend is around 50 lbs. If the actual cumulative weight exceeds the target value by more than 50 lbs, proportional adjustments need to be made to the weights of the additives and cement to compensate for the excess. Extra amounts of materials are generally added on top of the second half of the cement. It should be mentioned here that small differences in the concentration of critical additives (retarders, fluid Cement Sampling, Blending and Quality Control 3-77 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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loss, dispersants, etc.) can significantly alter the final properties of the blended product. While transferring the blend to the "transport" for delivery to the rig site, a sample must be taken for performing confirmation tests on the blend. Sampling procedures are discussed in more detail later (see Sampling). Important note: When extremely light additives (e.g. ceramic bubbles) have been blended in the cement, re-blending on location may need to be done to ensure the homogeneity of the blend. This is particularly critical offshore. Extremely light additives tend to "gravity segregate" during transport to the rig, and while being blown to the rig tanks from the boat on offshore jobs. A clean, empty tank of adequate capacity should be used on location to transfer the blend at least twice to re-blend it. Samples of the reblended material should be taken after the re-blending operation and if time allows it, sent to the lab for testing prior to the job. The dry blending procedures discussed above should also be applied to dry-blending of additives for spacers. Liquid Blending When Using Batch-Mixers After determining the total volume of mix-liquid to be blended and the minimum mix-liquid to be blended in each batch-mixer tank (when batch-mixing is used), an excess mix-liquid to be blended must be decided upon. This excess mix-liquid is needed to allow for extra volume required to fill lines and prime pumps, etc. In addition, some extra volume is needed to be able to effectively "fine tune" the slurry density during batch-mixing at the rig-site. The procedure normally used on location is to mix the slurry 0.2 to 0.5 ppg heavier than planned by transferring some of the mix-liquid to another clean tank containing the excess mix-liquid, then slowly adding some volume of the mix-liquid to the mixed slurry, while stirring and making measurements with a calibrated pressurized mud balance, until the target slurry density is obtained. Prior to commencing the liquid blending operations, all blending equipment must have been cleaned and inspected. The first critical operation in liquid blending is ensuring that the correct amount of water is added to the blender (batch-mixer tank). The source of the water must be checked to make sure is the same as was used during the laboratory testing. Batch-mixer tanks normally have barrel markers (volume indicators) to be able to tell how much volume of liquid is in the tank. These markers are sometimes not accurate, can be affected by the leveling of the tanks, etc. and therefore, should not be used as the only mean for measuring the water. However, they can be used to double-check the volume of water placed in the tank. One good method is to use a clean pump truck and to pump the water into the batch-mixer tanks from the truck's displacement tanks. The pump truck must Rev. 01/2002


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be well leveled, and all the lines, valves and connecting hoses to the batch-mixer must be completely full of water prior to measuring the water into the batch-mixer. After the correct volume of water has been added to the blender in accordance with the blend size design, the correct volumes of liquid additives are then introduced directly into the tank. Important note: liquid additives often need to be added to the mix-water in a pre-determinated order to maximize their effectiveness and to avoid some incompatibility problems. This order of addition must be followed during the liquid blending operation. This sequence should be the same that was used in performing the pilot tests. Liquid additives often come in 55 gal drums or 5 gal pails. It is important to make sure that all the containers are full (have not been partially emptied). Often it is assumed that a 5-gallon pail or a 55-gallon drum actually contain those volumes of liquid additives. This practice can potentially result in blends that do not contain the correct proportion of additives. A good way is to used a graduated container like a 5 gal bucket. The graduated pail can be used to check the volumes contained in the "5-gallon" pails. If measurements on several randomly selected 5-gallon pails indicate that they indeed contain 5 gallons of liquid, the contents of the pails can then be added directly into the mix hopper. Again the graduated bucket can be used to spot-check the volume in the 55 gal drums. This is normally done at the service company yard. One drum can be emptied using the bucket, and the volume checked. If it checks fine, the thing that needs to be done next is to make sure all the drums to be used are filled to the same height. When all of the additives have been introduced into the blender, the blend must be stirred for a minimum of 15 minutes to ensure that a homogenous mixture is obtained. A sample must then be taken for performing confirmation tests on the blend. Sampling procedures are discussed elsewhere. On the Fly Mixing Using Liquid Additives Cement slurries can also be mixed "on the fly" using continuous addition of liquid additives to the mix water. This technique is most often used in off-shore locations. Liquid additives may be dumped from gauge tanks into the mixwater tanks or more sophisticated computerized injection devices may be used. One important issue with this type of cement slurry mixing is the maintenance of the correct slurry density. Thus, calibration of the equipment and proper coordination of density measurement with the rate of addition of cement, mixing water and liquid additives is absolutely critical. Once the cement slurry leaves the mixing tank, there is nothing that can be done. It must be mixed correctly. Industry experience with liquid additives has been mixed mainly because of problems with dispensing systems and maintaining good control of slurry density. Ideally, the density of cement slurries needs to be controlled within +/-0.1 lb/gal. Cement Sampling, Blending and Quality Control 3-79 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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This is not always achieved even with the latest computerized equipment. Below is an example of a field experience illustrating mixing on the fly vs. batch-mixing. During the job, about 70 bbls of slurry were mixed on the fly. The following 100 bbls were mixed in a batch-mixer at the desired density of 15.8 lb/gal. The slurry in the batch-mixer was stirred in the tank while the first 70 bbls were pumped downhole. As seen in the figure, the density of the initial 70 bbls varied from 15.1 to 16.3 lb/gal. Figure 24: Slurry Density Variations While Pumping

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The following list contains other best practices and precautions when using liquid additives:

• The slurry mixing system must be capable of slurry density control of +/0.1 ppg.

• The liquid additive metering system should be tested for uniform and constant delivery of liquid additive.

• A constant inventory of required and actual usage of mix water and liquid additives should be maintained through the job.

• The dispersion of liquid additives throughout the mix water should be verified.

• Liquid lignosulfonate retarders should be avoided, unless their reliability has been carefully verified in the laboratory.

• Slurries should be tested in the lab, 0.5 ppg (59.9 kg/cu m) above and below the designed density to see the effect of density variation on properties.

• An onsite monitoring package capable of continuously recording rates and density should be run and examined during and after each job to ensure that the slurry is mixed to design specification. The scale for the density printout should be small enough to detect small variations in density.

• Cement delivered at different times should be isolated from any other cement.

• The cement, additives, and mix water used for design and testing should always be the same materials used on the actual job. Sampling of the Blended Cements The process of sampling a blend is as important as the process of blending since the samples are used to run confirmation tests on the blend. The success of the blending operation is measured by how well properly taken samples of the blend compare with the pilot tests of the lab slurry, within acceptable tolerances. Automatic Sampling One efficient method of achieving this is through the use of automatic sampling devices such as Halliburton's Accu-sample Dry Bulk material collector. Comparable devices are available from the other service companies. Many service company locations are equipped with these types of collectors. The devices enable samples of the blend to be automatically taken from the "stream" while the blend is being blown to the "transport". Cement Sampling, Blending and Quality Control 3-81 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The sampling frequency of the "stream" can be adjusted from once every four seconds to one sample every 1.5 minutes. If needed, two different sample rates can be pre-selected and the two rates can be used at will during the sampling process. The following are "ball park" sample settings for the device for different blend sizes: Figure 25: Example of Sample Taking for Typical Automatic Samplers Batch Size Sks

Sample Rate Seconds

Total Sample Collected Gals

50

4

0.5

150

20

0.5

250

20

0.75

For blends containing only fine materials such as cement, retarders, etc., the collector is assembled with four collecting holes (0.234 in. dia.) spaced across the width of the discharge pipe. For blends containing granular materials like silica sand, lost circulation materials, etc, a single hole (0.375 in. dia.) is used to collect the samples from the center of the stream. It should be noted that if the single hole arrangement is not available for sampling the coarser blends, plugging might occur if the four-hole arrangement is used. Under these conditions it will be better to sample manually (see below). Prior to taking the sample, the device must be set at the desired sampling rate, and it must be checked to make sure that it is operating properly and that it is free of material from previous jobs. Manual Sampling Many locations do not have automatic sampling devices. In these situations, manual sampling needs to be used. This practice, if done correctly, can also be very effective. It consists of taking the sample by using a discharge valve located on the line going from the scale tank or the blend tank to the transport. Prior to taking the sample, the valve must be purged of material from the previous batch. While sampling, small amounts (surges) of material must be taken by opening and closing the valve, throughout the transfer of the batch to the transport (usually sampling is started a few minutes after the start of the transfer operation, to make sure that the sample is representative of the current batch and it is not being affected by material left in the lines from the previous batch. A well taken sample needs to contain from 20 to 50 lbs of blended material.

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Sampling Liquid Blends When sampling liquid blends, a clean, unused container of at least one gallon capacity must be used. Prior to taking the sample, the blend must be agitated for a minimum of 15 minutes to ensure that a homogenous mixture is obtained. The sample is usually taken from a valve on the bottom of the blender while the blend is being agitated. The sample must not be taken until the valve and line leading to the valve have been purged. If the batch-mixer is not equipped with a sampling valve, the sample can be taken from the top of the tank by using a container and dipping it low into the body of the liquid. After taking the sample, the container must be tightly closed and labeled as mentioned before. A sample must be taken from each of the blend tanks. Composite Sample Preparation Each batch sample can be tested to check if the specific blend resembles the properties measured during the pilot testing. However, this can be extremely expensive and time consuming, and is not normally done. When done, it is only for small critical jobs (like squeezing or plug cementing). Normally what is done is that the different batch samples are mixed into one or two composite samples and the confirmation tests are run on the composite samples. This technique, when combined with the rigorous blending practices outlined in this section has been very successful in numerous jobs throughout the industry worldwide. One way to mix the different sample batches together is to place them in a clean drum or container and roll the container until the samples are completely mixed. However, depending on the number of the samples, location, etc. this is not always possible. What is often done is the following: each sample bag is thoroughly mixed (a large metal spoon can be used for this purpose). Next, three to four spoonfuls full of material are taken from each sample bag (or more if needed for volume), and placed into a clean "composite" bag. As a rule of thumb, the volume of the composite sample should be approximately equal to the average volume of the individual sample bags. The "composite" bag must be thoroughly mixed as before. Then the bag must be tightly closed and labeled "composite blend" and with the same relevant information as for the individual samples. A composite sample of the liquid blend is similarly prepared by thoroughly mixing (shaking) the contents of each container, and then transferring equal amounts from each container into a clean "composite" container. The "composite" container must be closed and thoroughly mixed as before. Then the container must be labeled "composite blend" and with the other important well information. All the samples dry and liquid, from each batch and the composite ones, must be saved in a dry environment (often in the laboratory) for future verification or post-analysis work. The sampling procedures discussed above should also be applied to the preparation of composite samples of dry and liquid blends of spacers. Cement Sampling, Blending and Quality Control 3-83 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Confirmation Testing The "composite" samples are used by the lab personnel to run the confirmation tests on the blends. To run the confirmation tests, the dry and liquid blends are combined in the same ratios as used in the pilot tests. The confirmation tests must be run using the same industry proven testing procedures that were used when running the pilot tests. First, the slurry density should be verified with a calibrated pressurized mud balance and then a thickening test should be run. Simultaneously, settling tests should be run. Next, free water, fluid loss, rheology, spacer compatibility and finally compressive strength tests are run. Following are some guidelines for tolerances to help decide the acceptability or rejection of the blended cement formulations. Slurry Density The pressurized mud balance density of the slurry needs to be within 0.1 ppg of the target density (as designed during the pilot testing). The same for the density of the blended spacer. Thickening Time The thickening time must not be less than the minimum required thickening time for the job. The minimum required thickening time for the job is computed as the estimated job placement time plus at least one (1) hour safety factor to account for unplanned events. Any preconditioning time which was used in the pilot test (to simulate surface batch-mixing) must also be simulated in the confirmation test. The thickening time should not run in excess of about 3 hours over the estimated job placement time. However, thickening times that run long may be considered acceptable as long as the WOC time (see compressive strengths) is adequate (see also important note below). Settling Test The slurry needs to pass the settling test. The blended spacer must also pass the settling test. Free Fluid The free fluid must be essentially the same as the one obtained during the pilot tests. For slurries designed to prevent gas migration, the free water needs to be zero (0) ml. Rev. 01/2002


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Fluid Loss The API fluid loss must be within about 10 ml of the pilot test result, with slurries designed to have "good" fluid loss properties. Larger variations can be accepted with slurries designed with higher fluid loss values (see important note below). Rheology The consistency of the "composite" blend should allow surface mixing of the slurry without difficulty. In addition, the rheological properties of the "composite" field blend should produce similar pressure drop losses as those predicted from the pilot testing. Spacer Compatibility The "composite" cement blend and spacer system must exhibit similar compatibility characteristics as observed during pilot testing. Compressive Strengths Compressive strength is perhaps the most difficult test to reproduce even during pilot testing. As a guideline, WOC times (particularly at liner tops) should be reasonably close to the WOC times determined during pilot testing. In addition, the compressive strengths of the composite blend should be reasonable close to the values obtained during pilot testing. Important Note All of the confirmation test results must be considered in assessing the quality of the blend. Some results may be more critical in a particular case, and this must influence the decision as to use or reject the blend.


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Section 4: Displacements

Displacing Cement Aims: • understand the overall process of replacing drilling mud with cement slurry in the casing-formation annulus • highlight the factors which influence success • review the use of spacers and flushes and the importance of mud properties • review flow rates during hole conditioning and mud displacement.

The Displacement Problem in a Nutshell The ideal outcome is for the drilling mud in the annulus to be completely replaced with cement slurry. The slurry, when set, will support and protect the pipe and provide zonal isolation during the life of the well. In most cases the result is less than ideal. Displacement efficiency is measure as the percentage of mud removed from the section of annulus to be cemented. Most experts agree that the best that can be expected, in a very well conducted cementing operation, is to displace and replace with cement slurry, about 95% of the mud in the annulus. In the best of the cases, 5% of mud is left in the annulus and that mud is capable of causing problems in the life of the well. For example, if we assume a case where 1500 ft of annulus formed by 9-5/8" casing in 13-3/8" hole is to be cemented, 5% of the annular volume amounts to 6.3 bbls of mud (5% of 126 bbls). If, after the cement job, this mud remains in long channels within the bulk of the cement, and/or against the casing or the permeability, then there is a good chance that problems may develop in the life of the well (casing corrosion, zonal communication, etc.). On the other hand, if the 5% mud is partially dispersed within the bulk of the cement slurry, and/or left in small pockets or short channels that do not contact the pipe or communicate between zones, then serious problems will not be observed. Displacements 4-1 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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To be able to remove as much as possible of the mud in the annulus, the industry has developed a variety of methods and techniques. Some of them are purely mechanical such as pipe movement (with or without scratchers), casing centralizers, turbulators. Others depend on hydrodynamic effects such as fluid turbulence, fluid stress at the formation wall, filter cake erodibility. A frequent complicating factor in the displacement process is that cement slurries and drilling fluids are chemically incompatible. When mixed, chemical components contained in the fluid formulations react with each other, generating undesirable viscosity increases and loss of fluid loss control. The formation of viscous fluid in the annulus can seriously jeopardize the displacement. Channeling of the cement slurry can bypass the mud. To reduce the chance of cement slurry and drilling fluid contacting each other, the industry has developed fluids known as spacers (and/or flushes) that are chemically friendly with both cements and the muds. These fluids are pumped ahead of the slurry. The simplest flush or spacer is water.

Fluid Incompatibility Basically, mud systems belong in one of two categories – oil based or water based. Oil based systems are formulated with a variety of 'oils', ranging from diesel to more sophisticated, more environmentally friendly chemicals such as esters, LAO’s. In general, cement slurries are not compatible with water base muds, but they tend to be even less friendly with oil based systems. Incompatibility problems generally manifest themselves by viscosity increases (in some cases forming almost solid masses). However, mixing can also degrade fluid loss control, free fluid and compressive strength.

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The illustration of a cement slurry/water based mud incompatibility, is the putty-like mass formed soon after mixing.

Figure 1: Example of cement Slurry-Water Base Mud Incompatibility Cementing of wells drilled with oil based muds presents several problems:

• Incompatibility • Downhole surfaces are oil-wet • Some OBM’s contain high concentrations of salts which can impact slurry setting However, there are significant advantages with OBM:

• holes drilled with oil based muds are normally are closer to "gauge" than holes drilled with water base muds. This helps because good mud displacement is easier with minimum washouts.

• they do not tend to build excessive gel strengths downhole. This also helps in the displacement process.

• Good fluid loss control of OBM will reduce the potential for thick, "mushy” filter cake, again aiding the displacement process. OBM filter cakes are usually thin, tight and plastic. So, drilling with OBM – or synthetic OBM - often facilitates good cementing. Again, recognizing the importance of the mud in obtaining a good cement job and the need to integrate all aspects of the well planning. Displacements 4-3 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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One aspect of the placement process that needs special attention with oil base muds is the spacer design. In wells drilled with OBM, the surfaces are normally left oil-wet. Since cements do not bond to oil-wet surfaces, every attempt needs to be made to render the surfaces water-wet before they are contacted by the cement slurry. (In fact, cements do not bond well to water-wet surfaces either but there is better adhesion). Spacer fluids used with oil base muds must contain surfactants capable of water wetting the surfaces. Many spacers and flushes are available from the service companies. Since every well situation is different, it is not possible to make "blanket" statements as to which systems are the best. Field successes, or failures, should always be analyzed to assist in determining the degree of effectiveness of a given system. The make-up and chemistry of the mud system will influence the choice of surfactants so it is important to use samples of the actual mud. An example of laboratory data collected showing some viscosity incompatibility between an oil based mud and a cement slurry is given below in Table IV-1. Compare, for example, the readings for the mud and the neat cement slurry (100%) with the mixtures of 75/25 and 50/50 (OBM/Slurry). Figure 2: Example of Some Viscosity Incompatibility Data - an Oil base Mud and a Cement Slurry Fann Viscometer Readings OBM/Slurry %/%

Temp F

600

300

200

100

6

3

100/0

72

209

131

102

70

30

28

100/0

150

95

66

55

43

24

22

95/5

72

252

160

128

88

37

35

95/5

150

118

85

73

58

32

30

75/25

72

390

262

232

178

78

74

75/25

150

280

206

178

141

84

79

50/50

72

254

130

96

64

10

10

50/50

150

296

290

206

68

56

40

25/75

72

62

32

22

13

2

2

25/75

150

70

40

28

18

4

4

5/95

72

42

22

15

9

1

1

5/95

150

36

20

14

10

2

2

0/100

72

35

17

12

7

1

1

0/100

150

24

12

9

5

1

1

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Rheological Properties Rheological Models Detailed procedures for rheological measurement are contained in the document API RP-10B. In addition, methods and equations for the calculation of pressure drops and flow regimes are given in the same document. Here we will only briefly review these topics. To be able to characterize the flow behavior (friction pressures, flow regime) in any geometry (pipe, annulus), a rheological model that best represents the viscometry data must be selected. The data obtained using a rotational viscometer is converted to shear-rate and shear-stress data. A rheological model for the fluid is then selected by regression analysis or by plotting the shear-rate/shear-stress data, and deciding on the model that best represents the data. Rheological models describe the relationship between shear-stress and shear-rate of a fluid. The most commonly used models of drilling fluids, spacer systems and cement slurries are the Bingham plastic and the Power Law models. However, three parameter models are being used more and more throughout the industry. Newtonian Fluid Model. When plotting shear-stress versus shear-rate on Cartesian (rectangular) coordinates, a fluid behaving as a Newtonian fluid will generate a straight line through the origin with a positive slope (Figure Curve A). This is a model that often represents preflushes (un-weighted fluids) pumped ahead of spacer fluids during cementing operations. Bingham Plastic Model. When plotting shear-stress versus shear-rate on Cartesian (rectangular) coordinates, a fluid behaving as a Bingham Plastic will generate a straight line with a positive shear-stress at zero shear-rate (Figure Curve D) Power Law Model. When plotting shear-stress versus shear-rate on Cartesian (rectangular) coordinates, this model will produce a curve with zero shear-stress at zero shear-rate (Figure Curves B and C).


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Figure 3: Rheological Models

Selecting a Rheological Model The shear-stress, shear-rate data of the fluid should be analyzed against the different rheological models. Often, regression analysis is performed. The model with the best fit is then selected. Once a model has been selected, the equations developed for that model are used to calculate, for example, the pressure drop for the given fluid in a given geometry. Again, the equations for the different rheological models are contained in RP-10B. The calculations are normally performed using computer simulators. Factors Affecting Rheological Measurements As seen, temperature can have a marked effect on the rheological properties of cement slurries, spacer fluids and drilling muds. The rheology of the fluids should therefore be measured at temperatures that are representative of the well conditions. If the BHCT of the well is less than 185F, the rheology is often measured at a temperature between the surface and the BHCT. If the BHCT is higher than 185F, the rheology is then measured at 185F. This assumes that a HPHT rheometer is not available. In critical wells, however, an effort needs to me made to measure the rheologies of the fluids at realistic well temperatures using a HPHT rheometer.

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In a well, the temperature varies up and down the casing and the annulus. Strictly speaking, the rheology should be measured at several representative temperatures covering the range anticipated. Rheology measurements are affected by sedimentation tendencies, chemical reactions and other time and shear effects. Calculations using rheology data should be expected to contain a degree of uncertainty and need to be handled accordingly. Pressure does not affect the rheology of water base fluids (cement slurries and spacers) as much as temperature. However, for oil base muds, pressure – as well as temperature - can have a marked effect on the rheology.

• Mud Conditioning and Hole Monitoring • Hole conditioning, in general terms, prepares the hole for running casing and cementing. Hole conditioning should be done before pulling out to run casing and also once casing is on bottom. Hole conditioning, accomplishes several goals:

• Mud rheological properties are lowered to reduce surge pressures and facilitate mud displacement – removal of low gravity solids and chemical treatment

• • • • •

Mud fluid loss is tightened Remove any cuttings or cavings Break mud gels Remove any gelled mud in pockets Circulated out any gas

Some of these tasks should occur while still drilling to section TD. The condition of the mud is the most important factor in obtaining good displacement and a successful cement job. Thus, one of the issues is how long to circulate? Traditionally, “rules of thumb” such as circulating bottoms-up twice or circulating the open hole volume have been used. Displacement studies have shown, not surprisingly, that “rules of thumb” can be unreliable. More quantitative method have been used such as the “tag” or “dye tracer” methods. The technique involves adding a dye or other marker (e.g. a carbide slug) to the drilling fluid and circulating the well at a constant pump rate. When the dye or marker is detected in the return line, the percentage volume of mud circulating can be determined based on the well geometry and the open hole caliper log. Displacements 4-7 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The use of such tracers, however, is time consuming and subject to gross errors in poor hole conditions – exactly those which most need the assessment. At best, the return is not a sharp peak but extends over a considerable time. Analysis is difficult. A possibly more reliable method continuously estimates the circulatable hole (the percentage of open hole mud volume that is actually moving during conditioning). This provides knowledge of when circulation at a given rate is no longer providing additional benefit. With this information, the circulation rate can be increased and/or other techniques can be applied (pipe movement) to improve the percent of circulatable hole. A knowledge of how much openhole mud is circulating is of particular importance in highly deviated/horizontal holes, due to the potential presence of solids beds on the low side of the hole. The continuous monitoring technique uses a software package, and it is based on very accurate measurements of wellhead pressure and flow rate of the drilling fluid while conditioning. The wellbore geometry, including an accurate caliper log, and the drilling fluid rheological properties must also be known to predict the percentage of circulatable hole. The calculation is simply based on the pressure drop that should occur in the openhole section of the annulus. If the hole has 100% of the drilling fluid circulating, a certain pressure drop for the openhole section can be calculated at a given flow rate. If less than 100% of the drilling fluid is moving, the annular flow area will be smaller and the pressure drop across that annulus will be higher. The software used calculates the percentage of circulatable hole based on the actual hole size (caliper). An example of the use of this technology in an actual well is shown in the following figure. Again, as with the tracer approach, this technique is difficult to apply, time consuming and subject to some error. However, just monitoring pressure against time for a couple of flow rates can help establish whether mud is being brought into circulation or not.

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10

100

Efficiency

8

80

Rate

60

6 Pressure 4

40

2

20 Designates Pipe Movement

0 0

30

60

90

Pseudo-Displacement Efficiency (%)

Wellhead Pressure (100 psi) Flow Rate (bbl/min)

Cement Manual

0 120

Time (min)

Figure 4: Wellhead Pressure vs. Displacement Efficiency with Pipe Movement During hole conditioning, it is necessary for the bulk of the mud to be moving (circulating). The goal of the conditioning process is to end up with a “highly mobile mud” across the entire annular cross-section. If this is not done, the situation depicted below may occur.

LOW MOBILITY MUD

MOBILE MUD

FILTRATE

CEMENT

FILTRATE

FILTER CAKE CASING

FORMATION

Figure 5: Cementing with Unconditioned Drilling Mud Displacements 4-9 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Several investigators have conducted research on hole conditioning, mud properties and displacement. Example, ideal drilling fluid properties to be achieved before cementing a vertical well are given in the Table below together with suggested downhole Yield Point (YP) for drilling fluids used in highly deviated and horizontal wells. As seen, the suggested YP for deviated wells is higher than for vertical wells. This higher YP is necessary to minimize solids settling from the mud on the low side of the hole (barite settling known as sag). If solids settling from the mud is not prevented, a solids channel can form. These solids channels are very difficult to remove. Also, barite sag can lead to loss of well control due to the resulting effective reduction in mud density (hydrostatic head). To achieve the properties given at downhole conditions, the properties may need to be higher at the surface. Alternatively, if the properties are adjusted at surface to be close to the values given in the tables, the properties downhole may not have the desired values due to temperature and pressure effects.

Figure 6: Suggested Downhole Drilling Fluid Properties for Vertical Wells Property

Recommended

Preferred

Yield Point (YP) (lb/100 ft2)

10 or less

2

Plastic Viscosity (PV) (cp)

20 or less

15

Fluid Loss (FL) (cc/30 min)

15

5

Gel Strength (10 sec/10 min)

Flat Profile (Not a progressive gel)

Figure 7: Suggested Downhole Drilling Fluid Yield Point for Deviated Wells

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Deviation Angle, °

Yield Point at 72°F, (lb/100 ft2)

45

15

60

20

85

28

90

30 Displacements 4-10

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To adjust drilling fluid properties prior to cementing, the muds may be treated with additives (dispersants, etc.) in the mud pits prior to circulation and/or during circulation (conditioning). The properties that are normally adjusted are the rheology (PV, YP and gels) and the fluid loss of the drilling mud. Filtercake thickness is related, among other things, to the fluid loss of the mud. A thick mud filtercake is not desirable because it is hard to remove, does not bond to cement and can lead to poor long-term zone isolation. To minimize soft thick filtercake a low fluid loss is needed. Mud cake can easily be checked by the mud engineer and the thickness will be reported on the Mud Reports. Gel strength development is another property that should be checked and adjusted as needed. Muds with 'flat' get strength profiles - those that do not increase much with time - are desirable. WBM’s in poor condition need to be avoided. Again, the mud properties will affect the success of the cementing. Poor mud – poor cement job.

Minimization of Channeling Research work has shown the following practices will help minimize channeling:

• Centralize as much as possible • Density of the fluid doing the displacing needs to be higher than the density of the fluid being displaced

• The viscosity of the fluid doing the displacing needs to be higher that the rheology of the fluid being displaced. In cases where the pore/frac window precludes density differences then a rheology hierarchy should be used to minimize channeling. An improved technique over conventional concepts of density and rheology hierarchies is to use a pressure drop hierarchy of the mud, spacer, and cement slurry. This means that each fluid should have a higher pressure drop in the annulus at the given pump rate, and at the given annular location, than the fluid above it. Pressure drop is a more comprehensive way to approach minimization of channeling and relates to the shear stress at the wall developed as the fluid moves. When using such a pressure drop hierarchy, the rheology (and if possible the density of the fluids) needs to be adjusted for the given annular configuration and pump rates to be used. These calculations are normally performed using a cement job simulator. Displacements 4-11 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The concept of pressure drop hierarchy explains why it is possible to effectively displace a heavier fluid with a lower density one. If the lower density fluid has a rheology such that at the given pump rate and in the given section of the annulus, it generates a higher pressure drop (wall stress) than the heavier fluid, it will displace the heavier fluid with minimum tendency to channel. A good example is hole cleaning using high consistency foamed fluids.

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Erodibility Technology Wellbore Condition The outcome of a primary cementing operation is greatly influenced by the condition of the wellbore at the time the cement slurry is pumped. The Figure shows the condition in a wellbore across permeability, at the end of drilling with a poor WBM after running casing.

Figure 8: Typical Wellbore After a Shutdown Period This figure shows dense filtercake next to the formation wall, covered by partially dehydrated gelled (PDG) drilling mud and moderately gelled (MG) mud. Moderately gelled mud has been defined as a portion of mud that has developed gel strength in the absence of shear during static periods. Partially dehydrated gelled mud is mud which, in addition to developing static gel strength, has also lost some filtrate. This both densifies it and makes it thicker. In general, a poor quality WBM is most likely to produce this scenario and a good quality OBM the least likely. If a poor WBM is being run such that these properties occur the best course of action would be to remove the mud company. Erodibility Technology 4-13 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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It has been found through large scale experiments that the level of hole cleaning, and the efficiency of the cementing job, is controlled by the degree of mud dehydration across the openhole permeability. Tests have shown that displacement of the MG mud is not the real problem during primary cement jobs. The real difficulty is the removal of the PDG mud from the wellbore. The Figures below illustrate this. They show PDG mud and filtercake trapped between the cement and the permeable formation after large-scale laboratory cement jobs.

Vertical Hole

Inclined Hole

Figure 9: Trapped PDG Mud and Filtercake Through a joint research effort, a laboratory cell was designed and built to investigate gelled mud displacement. This cell is called an "erodibility cell."

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Figure 10: Diagram of Erodibility Cell


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Figure 11: Photo of Erodibility Cell Definition of Erodibility Erodibility has been defined such that high values would mean the given PDG mud would be easy to erode. On the other hand, low values would mean the PDG mud would be hard to remove (low erodibility). Thus, erodibility was defined as inversely proportional to the shear stress needed to remove the PDG mud. Mathematically, erodibility was defined as: E = 600/τw where τw (lbf /100ft2) is the stress needed for removal at the interface between the flowing fluid and the PDG mud. It was found that chemical attack is an extremely effective way to increase the removal of PDG mud. It was shown that certain chemical treatments allow effective removal in situations where shear stress at the wall alone could not be used because of the high pump rates required. In other words, chemically it is possible to cause the PDG muds (and filtercakes) to erode at substantially lower interfacial shear stresses. Rev. 01/2002


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Caution needs to be exercised in so far as different mud systems are likely to behave differently due to their chemical and physical make-up. This again emphasises how important the mud properties are to the physical displacement process. Erodibility “Rules of Thumb” Experiments thumb":

• • • •

with the erodibility cell have suggested the following "rules of

Mud systems with erodibilities of 5 or less are very hard to remove. PDG muds erodibilities around 10 are moderately hard to remove. Systems with erodibilities around 20 are moderately easy to remove. Erodibilities around 20 to 30 indicate systems that can be remove fairly easily.

• Erodibilities above 30 are very desirable (systems are quite easy to remove). Example of Field Application of the Erodibility Technology Some computer simulators are now able to make erodibility calculations. However, to help understand the process, the following example goes through the process, step by step, how erodibility can be used to improve cementing job success. The Problem It is necessary to recommend a spacer design and the flow rate needed to remove the PDG mud from the open hole in this well. As a first approach, it is planed to use conventional spacer systems that do not chemically attack the PDG mud. The well has 9-5/8 in. (40 lb/ft) intermediate casing set at 10,000 ft. Production casing (5-1/2 in., 17 lb/ft) will be set at 13,000 ft in an essentially gauge hole of 8 in. There is a 100 ft washout zone near the shoe of the 9-5/8 in. casing with an average hole diameter of 9.0 in. Fracture gradient at the bottom of the hole is 17 lb/gal equivalent. The cement slurry to be used is a 16.0 lb/gal system with a Fann rheology of 124, 84, 68, 51, 23, 13. It will be brought back 500 ft into the overlap. The mud density is 15 lb/gal. PV = 15 cp, YP = 10 lb/100 ft2. Using the erodibility cell, its erodibility was determined to be 12. Erodibility Technology 4-17 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Calculations The shear stress (τw) needed to remove the PDG mud is: 600/12 = 50 lbf/100 ft2. The needed pressure drop in the open hole is: P = 4 x L x τw /De Where L is the length of the open hole, and De is the equivalent diameter (hole diameter minus casing O.D.). If we calculate the pressure drop in the open hole in psi/ft using the shear stress in lbf/100 ft2 and the equivalent diameter in inches, then the previous equation can be written as: P = 0.00333 x τw/De Going back to our example well: P = 0.00333 x 50 /(8 - 5.5) P = 0.067 psi/ft (pressure drop per linear foot) is the pressure drop that is needed in the open hole to erode the PDG mud and filtercake. The next step is to design spacer systems and to calculate their pressure drop per foot of open hole configuration for this well to see if they are capable of developing the needed pressure drop of 0.067 psi/ft at reasonable pump rates. Spacer Design For our imaginary example, three spacer systems were designed for this well. The systems were designed to be compatible with the mud in the hole and the cement slurry to be used, and when tested for settling, the spacers did not settle statically or dynamically. All the spacers had a density of 15.5 lb/gal, and they all had good fluid loss control. The table below gives the rheology of the spacer systems. Figure 12: Spacer Rheology Spacer

Rheology Readings

600

300

200

100

6

3

1

29

17

13

11

5

2

2

70

40

30

20

10

5

3

120

70

53

36

15

8

Using a computer program, the pressure drop for each of the three spacers was calculated for this well's open hole configuration. The pressure drop for water was also calculated. The following table summarizes the results obtained: Rev. 01/2002


Cement Manual

Pressure Drop in the Well Spacer 1 Rate

Hole Size

Pressure Drop

BPM

in.

psi/ft

12

8

0.0636

12

9

0.0219

14

8

0.0831 *

14

9

0.0286

Rate

Hole Size

Pressure Drop

BPM

in.

psi/ft

8

8

0.0404

8

9

0.0181

12

8

0.0713 *

12

9

0.0238

14

8

0.0936

14

9

0.0313

Rate

Hole Size

Pressure Drop

BPM

in.

psi/ft

5

8

0.0549

5

9

0.0251

8

8

0.0728 *

8

9

0.0333

14

8

0.1027

Spacer 2

Spacer 3


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14

9

0.0466

Rate

Hole Size

Pressure Drop

BPM

in.

psi/ft

12

8

0.0375

12

9

0.0120

14

8

0.0498

14

9

0.0160

Water

From the table above, spacer 1 would have to be pumped at 14 BPM, spacer 2 at 12 BPM and spacer 3 at 8 BPM to erode the PDG mud and filter cake in this well. Notice that none of the spacers developed the needed pressure drop in the 9 in. hole (washout zone) even at the higher rates. This indicates that there is a great chance that PDG mud will not be removed from the washout zone. This example helps explain why it is so hard to get good cement jobs in holes with large washouts. The water did not develop the needed pressure drop even at 14 BPM in the 8 in. hole, but reactive flushes should not be discarded from the screening of spacer fluids. Certain spacers and flushes can increase the erodibility of PDG mud by chemical means. ECD Calculations Again a computer program was used, this time to see if the selected flow rates for each of the spacers would allow the job to be pumped without fracturing the well (without exceeding the 17.0 lb/gal equivalent fracture gradient). For each set of calculations, it was assumed that 1,000 ft (in the annulus) of spacer would be used in the job. Maximum ECDs at the Selected Rates Rate BPM

Maximum ECD at the Bottom lb/gal

1

14

16.4

2

12

16.3

3

8

16.1

Spacer

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As can be seen from the table, the three spacers at their engineered rates would work (maximum ECD's were below the 17.0 lb/gal fracture gradient). Final Testing With the Erodibility Cell To fully utilize the erodibility technology, the final selection as to which spacer and flow rate combination to use for the job would be determined using the erodibility cell. Each spacer would need to be tested (pumped at the cell rate equivalent to the field rate selected), over a PDG mud and cake bed deposited with the same mud, to confirm the design (removal of the PDG mud bed). Based on those tests, the best spacer would be chosen. Reactive chemical flushes would also be tested at this stage. Obviously, this is a very time consuming and labour intensive exercise which will always be subject to the difficulty of having a mud sample truly representative of that in the well at section TD. The best that can be expected is to be able to bracket the likely properties of the type of mud in use. If it looks poor, replacement should be considered.

The Phenomenon of Free-fall In the great majority of primary cement jobs, the densities of the spacer fluid and cement slurry are greater than the density of the mud. Because of this density difference, the well "goes on vacuum" or "U-tubes" while the heavier fluids are being pumped down the casing. Free-fall presents many problems in primary cementing. For example, while the heavy fluids (spacer, slurries) are free-falling, a vacuum is created at the wellhead. This can make removal of a cement-head lid (to drop a top cement plug) difficult and time consuming. The fundamental cause of free-fall is the difference in densities between the spacer, the slurries and the mud in the hole. The phenomenon of free-fall is similar, in principle, to the U tube manometer problem. In a U-tube manometer, with two different density fluids, there is a difference in the elevation of the two fluids at rest. If this equilibrium is changed, or disturbed in any way, the fluids will oscillate until the equilibrium position is again reached. In the case of free-fall during a primary cementing job, the fluids also tend to flow towards an equilibrium position. For the sake of illustration, imagine a case where enough volume of a cement slurry was pumped in a well to cause the well to "go on a vacuum" and then no more slurry or drilling mud was pumped after that. In this situation, the fluids would also free-fall seeking an equilibrium position. The real problem is much more complex since fluids are continuously being pumped at the surface, while the free-fall phenomenon is taking place. The "new" fluid being pumped at the Erodibility Technology 4-21 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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surface eventually lands on top of the free-falling column and has an added direct effect on the free-fall phenomenon. The frictional pressures generated by the flow of the fluids have a strong effect on the free-fall phenomenon. Frictional forces resist and slow down the rate of free-fall of the fluids. At a given time during free-fall, the flow rate of the fluids is dictated by the difference in density of the fluids, by the length of the column of each fluid in the well, and by the frictional forces which in themselves are a function of the free-fall rate. During free-fall, the fluids move at flow rates which change constantly and are not equal to the surface pumping rate. Initially, the free-falling column of fluids moves faster than the surface pump rate. Eventually this rate reaches a maximum value and then slows down as the heavy fluids get close to the bottom of the well or even "turn the corner," and the lighter displacement fluid is pumped behind them. During the deceleration stage of free-fall, the fluids in the well may move at rates below the desired minimum rate for the job.

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The early acceleration stages of free-fall cause a "partially empty" or "discontinuous" zone to form in between the free-falling column and the wellhead. In this discontinuous section of the well, the fluids free-fall at low pressures (even under vacuum) and do not fully fill the inner diameter of the pipe. The length of this discontinuous zone constantly changes during the entire free-fall period. It is nonexistent at the onset of free-fall, reaches a maximum length sometime during free-fall, and eventually becomes nonexistent again at the end of freefall.

Figure 13: The Phenomenon of Free-Fall Sometimes the pump rate at surface is increased to "catch up with the plug." Unfortunately, in some cases, this causes the free-fall period to terminate abruptly by "running into the plug" too fast. It is possible to create large pressure surges in the well which can be detrimental, possibly causing damage to the casing or fracturing the well across weak zones. Mathematical models (computer simulators) have been developed by the industry. The models solve for the flow rate in the well at anytime during free-fall by assumErodibility Technology 4-23 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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ing that the surface pressure is essentially equal to zero while an "empty" gap exists in between the free-falling column of fluids and the wellhead. The development of free-fall models has substantially improved the industry's understanding of the phenomenon of free-fall. With the use of the mathematical models, job designs can be performed for specific cases. Some general conclusions have been reached through the use of simulators: • It is possible to estimate the free-fall rate of the fluid column at any time during the job. Since the column of the fluid is continuous throughout the entire annulus, the rate of free-fall is equal to the annular rate of returns at the surface, assuming the fluids are incompressible. • In general, equivalent circulating densities (ECD's) during the accelerating stages of free-fall do not appear to be excessive enough to cause lost circulation problems during most typical jobs. Simulation runs indicate that even during highly accelerated free-falling periods, ECD's are less than the ECD's after the cement is in place behind the pipe, at the end of the job. • It is apparent from computer runs using simulators that many previous jobs pumped "under turbulent flow" were, at least during the decelerating stages of free-fall, not in turbulent but very likely in laminar flow. • It is possible to get a good approximation of the time (or volume needed) for the displacement fluids to "catch up with the plug" when a well is on a vacuum during cementing. • When the fluids catch up with the plug, it is possible to estimate the rate at which the free-falling column of fluid is moving. This can prevent "running into the plug" at rates too different from the rate of the free falling column in order to avoid damaging the well. • It is possible to design surface pumping schedules to control the rate of free-fall above certain minimum limits, for example to be able to use the erodibility technology. • It is possible to simulate shutdowns and obtain a good estimation of free-falling rates during pump shutdowns. The time needed for a free-falling column of cement to come to a complete stop and its position in the well at the end of a shutdown can also be estimated. • Experience with simulators indicates that shutdowns from 15 to 20 minutes are often enough to cause the free-falling cement column to come to a complete stop. • Free-fall can be prevented by choking the annular returns Rev. 01/2002


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Optimization of the Displacement Process The transition from hole conditioning to spacer pumping to cement and mud displacement needs to be done with minimum shutdown time to minimize mud gel strength development.

Importance of Proper Centralization and Centralizer Selection Centralisation is a trade-off of a number of variables: • Type of centraliser – bow-spring, rigid or solid • Design, robustness and quality of manufacture • Running force/hook load • Number and placement • Hole washout A well planned centralization program should aim for a minimum of 80% standoff. However, this may require so many centralisers that the casing will not run. If the well has severe doglegs and deviations above about 20 degrees, a computer simulator must be used to optimize the centralizer program. Extended reach and horizontal wells require careful planning and use of computer simulators. Many different types of centralizers are available from the service companies. Some of them are designed for specific applications such as slim holes, and extended reach wells. The general classification of centralizers includes flexible (bow), semi-rigid and solid. Construction materials include aluminum, bronze, aluminum-zinc alloys and steal. They all have different applications depending on the well conditions and configuration. Below are some general guidelines for the selection of centralizers for a given well application. For vertical holes, the normal practice is to use bow spring centralizers. Solid centralizers including 'turbulator' types (blades in an angle to cause the fluids to swirl) are used in narrow annuli, but normally they do not provide as good a standoff as bow spring centralizers. When the pipe is to be rotated, bow spring centralizers can be installed over stop rings (and in some cases over pipe collars if annular clearances allow). This faciliErodibility Technology 4-25 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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tates running in hole easily without hanging up (for pipe rotation, the pipe should be free to turn inside the static centralizers). However, this type of installation is not good if reciprocation is used because the pipe cannot be rotated. Reciprocation requires the centralizers to be placed between collars, or between stop rings that are installed far enough apart to accommodate the reciprocation stroke without moving the centralizer. This installation, however, may cause the centralizers to be subject to damage while being run in very tight or high angle holes. When using stop rings, the set screw style, and/or set screws with 'dogs', have been found to produce the highest holding forces. Nail, or pin, type have been found to produce the lowest holding forces. For low deviation (say less than 20 - 30 degrees), bow spring centralizers are normally used as long as the design calculations (computer program simulations) show that they are adequate to provide the desired standoff. Semi-rigid (including double-bow) centralizers are often the next choice. Positive stand-off centralizers (straight vanes, turbulators, etc.) are used when the bow and semi-rigid types are not adequate. In any case, it is very important to try to maintain high levels of standoff (80+%) whenever possible. In some high angle holes, the 'turbulator' type centralizers have been found to “plow” their way into soft formations, making running of the casing difficult. For very narrow annuli, positive standoff centralizer subs may be needed, but they are expensive. For highly deviated and horizontal holes, the semi-rigid (double bow) type centralizers are often considered due to their potential higher standoff over the semi-rigid vane type. Double-bow centralizers generate less starting and running forces than typical bow centralizers, but better restoring forces than conventional bow spring centralizers under lateral forces. Some operators have used combinations of rigid and semi-rigid centralizers in highly deviated and horizontal holes to help enhance the chance of getting a good cement job. In all cases, standoff needs to be calculated at the lowest point of casing sag, in between the centralizers. Recently, roller blade type centralizers have become available. These solid type devices can greatly help running of casing in extended reach wells. The rollers dramatically reduce the drag and torque in these wells. Below is an example of the use of these centralizers in an extended reach well, comparing the drag forces to an offset well where the centralizers were not used.

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Figure 14: Example of Drag Reduction by the use of Roller Blade Centralizers

The Importance of Pipe Movement The reason for pipe movement is to help break up and remove as much of the mud in the hole as possible. Pipe movement is an integral part of best practices to obtain a good cement job. From many large scale laboratory experiments and from field experiences, it has been well established that the best way to achieve a good cement job is to: • properly condition the hole, • adequately centralize the pipe, • run the proper type of scratchers (cable loop wipers), • move the pipe, • use well designed spacer fluids, • use a pressure drop hierarchy when displacing the fluid in the annulus, • pump at rates high enough to remove any partially dehydrated gelled mud across permeability When these things are done, comparison of results from pipe reciprocation and rotation using scratchers has consistently shown little difference between the Erodibility Technology 4-27 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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movement methods. The correct type of scratchers need to be used with each technique. For reciprocation, it is necessary to use the reciprocating (horizontal) cable loop type. For rotation, the rotating (vertical) cable loop scratchers should be used. The open wire type scratchers have been found to bend easily (the wires), and it is doubtful that they can perform downhole. In fact, the integrity of scratchers and centralizers is a very important aspect. These items have to be extremely robust to survive running into the well. Experience has often indicated that, in practice, these items are not robust enough and provide a source of junk in the hole rather than performing their intended function. This does not detract from the philosophy that centralisation, pipe movement and mechanical disturbance of the mud cake will all enhance the quality of the cement job. Pipe Movement vs. Displacement Efficiency Conditions: 16 lb/gal Drilling Mud, 16.7 lb/gal Cement Slurry, 4 bbl/min Pump Rate, and 60% Pipe Standoff

Pipe Movement

Displacement Efficiency (%)

None

65

20 rev/min

97

Pipe Movement in Deviated, Highly deviated and Horizontal Holes With reciprocation, the pipe may get stuck, potentially leaving uncased openhole at the bottom of the well. Reciprocation sometimes limits pipe movement to only pre-cement job use. In this type of well, rotation has an advantage over reciprocation since, due to the torque forces, it tends to pull the fluids all the way around the pipe (better mud removal). Recently, roller blade centralizers have been developed with rollers that reduce the torque during rotation. Those centralizers contain two sets of rollers. One set for the reduction of drag during running of the casing, and another set to reduce torque to allow the casing to be rotated. Pipe Movement for Liners Rotation is the preferred way to move liners. Liner hangers are available that permit rotation of long heavy liners, and liner rotation has become common practice even for horizontal wells. With liners, rotation is preferred because it tends to overcome some of the potential disadvantages of reciprocation: Rev. 01/2002


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• Eliminates the piston surge of the reciprocation down-stroke. • Eliminates the swabbing effect of the reciprocation up-stroke. • Eliminates the possibility of sticking the pipe out of position with respect to the desired setting depth. • It is less risky, when the DP and setting tool can be released from the liner prior to cementing. In all pipe movement scenarios, the best practice is to begin casing movement as soon as the casing or liner reaches bottom, and if possible, continue the pipe movement during hole conditioning and until cement is placed. Rotation should be at least 10 to 20 RPM. In the case that rotation cannot be achieved, for whatever reason, reciprocation is much better than no movement and should be attempted whenever possible. If reciprocation is applied, often strokes of 15 to 20 ft/min are used, but first perform surge/swab calculations to make sure the well is not damaged during pipe movement. In some slim hole applications, calculations may indicate that reciprocation cannot be done due to fracturing weak zones during the down-stroke. When moving liners it is, of course, necessary to make sure the rig crew do not exceed the string tensile or torque limits, connection yield, the makeup torque of the weakest connection, or the load rating of the bearing in the liner hanger. While reciprocating, the pipe should be lowered close to bottom occasionally, to keep the rat hole clean. Each stroke should be made to a depth of several feet (2-5 ft) below where the pipe will be finally landed. When the top wiper plug is due to bump, or if it appears that the casing is going to get stuck, pipe movement should be stopped, if possible, at the desired depth.

Modeling the Displacement Process Job Simulation Using Simulators Cement job simulators have been developed by service companies and operators. They include simulation of free-fall, calculate the circulating hydraulics, determine downhole pressures and attempt to take account of the mud displacement mechanics. To produce a good simulation of the job, the actual well trajectory must be used together with actual fluid properties and hole dimensions. Pre-job simulations need to be initiated as soon as possible - using assumptions - to help influence Erodibility Technology 4-29 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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the job design. Re-runs can be made very easily with the latest data, to optimize the job. Pre-job simulations will help with, among other things: • Optimization of the flow rates during well conditioning and cementing, for maximum mud removal. • Ensure that the fracture gradient in the openhole is not exceeded during the job. A very critical issue in some well conditions - tight liners, slimholes, etc. • Maintaining sufficient overbalance pressure across pressurized gas and/or fluid-bearing formations to maintain control of the well and prevent fluid invasion during pumping and shutdowns. • Optimizing spacer and cement properties (rheology, density) to maximize mud displacement. • Minimize the chances of channeling by properly designing a pressure drop hierarchy in the annulus for the fluids, from the top to the bottom of the annulus. When performing a pre-job simulation, the following information is needed among other data: • Accurate well geometry (including deviation) • Density and rheology of all the fluids (often rheologies need to be estimated from previous lab information until the slurry and spacer designs are completed) • Fracture pressures or gradient vs. depth • Pore pressures or gradient vs. depth Accurate Geometry A good caliper log (four or six arm) is needed to help simulate the openhole geometry as closely as possible to the real situation. This is of particular importance in slimholes, since relatively minor changes in hole geometry may make large differences in friction pressure (ECD) calculations. Fracture Pressure (Gradient) vs. Depth To be able to optimize the job without danger of breaking down weak formations, the fracture pressures (gradient) at different depths must be accurately known for the openhole section. Job pump rates are designed to stay below rates that may initiate lost circulation. Often the job is pumped fast at the beginning and then the pump rate is slowed to prevent the ECDs from exceeding the fracture gradient across weak zones. Rev. 01/2002


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12,600 16 ECD — lb/gal

Circulating Pressure — psi

Fracture pressure/gradient at 15,000 ft TVD 12,200

11,800 15 Fluids Pumped ➁ Dual Spacer ➂ Lead Cement ➃ Tail Cement ➄ Drilling Fluid

11,400

➃

➁➂

➄

11,000 0

400

800

1,200

1,600

2,000

2,400

Volume In —bbl Plot shows total annular pressure and equivalent circulating density vs. liquid volume pumped into the well.

Figure 15: Example of Job Pump Rates Reduced Toward the End, to Avoid Lost Circulation In highly deviated and/or horizontal hole situations, chances of exceeding the fracture gradient may often be more affected by the fluid rheology than by the density. This is because the contribution to the total pressure from the hydrostatic component is smaller in these types of wells than in vertical holes. Again simulators need to be used to optimize these situations. Pore Pressure vs. Depth Breaking down zones during placement of a cement slurry is always a concern, and so is maintaining sufficient wellbore pressure across gas and other fluid-bearing zones during the job, during potential shutdowns, and after placement of a cement slurry. To properly simulate the job, the depth and formation pressure (pore pressure) for each liquid and gas-bearing zone must be known. If zones are not properly considered, the result may be annular flow during or after cementing or even a blowout. When using preflushes, it is critical that the whole job be carefully evaluated because of the loss of hydrostatic head which may be generated by these fluids, particularly if channeling occurs. This is important in narrow pore/frac window wells, where low overbalance and the potential for gas migration is greater than in more conventional wells. Erodibility Technology 4-31 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Example of a Job Simulation: A Slim Hole Situation This section illustrate a slim hole cementing job simulation conducted using an industry available job simulator. The Table defines the well configuration. Notice that in this example, 3-1/2 in. casing will be set in a vertical 4-3/4 in. hole at a TD of 12,500 ft. The previous casing was 7 in. set at 1,500 ft. Wellbore Geometry Figure 16: Annulus Segments Top

Bottom

Hole

Casing Size

Depth ft

Depth ft

Length ft

in

OD in

Angle deg

0

1500

1500

6.1540

3.5000

.0

1500

12500

11000

4.7500

3.5000

.0

Figure 17: Casing Segments Top

Bottom

Hole

Casing Size

Depth ft

Depth ft

Length ft

in

Angle deg

0

12500

12500

3.00

.0

Float Collar Depth

2420 ft MD

Desired Cement Top

6000 ft MD

Total Casing Depth

12500ft MD

True Vertical Depth

12500 ft MD

The Figure below gives the preliminary data for the fluids to be pumped. The top of the cement slurry will be at 6,000 ft to cover a gas zone located at 7,500 ft. The gas zone has a pore pressure of 11.0 lb/gal equivalent and a fracture pressure of 13.4 lb/gal equivalent. The fracture gradient equivalent at TD is 13.8 lb/gal for this hole.

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Figure 18: Fluid Properties for the Slim Hole example The Figure below shows the erodibility calculations for the water-based mud which has an erodibility of 10. As mentioned before, an erodibility of 10 suggests that the PDG mud films from the mud are moderately hard to remove. This figure shows that for the spacer to remove the PDG, it needs to be pumped at about 3 bpm. For the mud to remove its own PDG, it would have to be pumped at 4.4 bpm (since as will be shown below, this well should not be circulated at rates above 4 bpm, this suggests that PDG mud will likely be present across the permeable zones during the cement job.) Notice also in the same figure that the selected rheologies of the spacer and cement slurry generate a pressure drop (wall stress) hierarchy going down in the annulus, starting with the mud. This suggests that there will not be a strong tendency for the fluids to channel if the casing is not properly centralized (the exception is the water preflush, but the main function of this fluid is to help dilute the mud ahead of the main spacer, and it is expected that it will be sacrificed/expended early during the displacement process). Notice also from Figure that the cement slurry would be able to remove the PDG films if pumped at rates above 2 bpm. This is good news and bad news. The mud Erodibility Technology 4-33 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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and mud films should be removed by the fluids ahead of the cement. Leftover mud will contaminate the cement slurry. On the other hand, if the PDG films are removed by the slurry without drastically affecting the set properties of the cement, this would still provide zone isolation. But again, this is not the ideal situation, and an effort should be made to have the fluids ahead of the cement slurry do the removing of the PDG mud films.

Figure 19: Erodibility Data for the 4-3/4"x 3-1/2" Annulus We saw above that the needed pump rate to have a chance for PDG mud removal by the spacer is 3 bpm for this cement job. However, as seen in the following figure, using only 10 bbls of the water preflush, the job could not be pumped at that rate. The Figure shows that at 3 bpm, the ECD at the bottom of the hole would go over 13.8 lb/gal before the end of the job.

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Figure 20: Job ECD's - 10 bbls Water One thing that could be done is to increase the water preflush to 30 bbls (about 3,000 liner ft in the annulus) to reduce the hydrostatic head. This would allow the job to be performed mostly at 3 bpm, having to reduce the rate to about 2 bpm toward the end. The obvious concern about running 3,000 ft of water in the annulus is the potential effect on the gas zone at 7,500 ft. The Figures shows that the ECD at 7,500 ft never falls below 11 lb/gal pore pressure at 3 bpm. Even at 2 bpm, the simulations suggest that the ECD across the gas zone would be above 11 lb/gal, toward the end of the job, when the rate would be reduced to prevent lost circulation. Using the 30 bbls of water, at the end of the job, the shut-in hydrostatic pressure across the gas zone would be 11.7 lb/gal.


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Figure 21: Job ECD's - 30 bbls Water The process of optimization outlined above indicates that the job could be done without losses, and that good PDG removal and minimum channeling would be expected if the job is pumped at 3 bpm, and if 30 bbls water pre-flush are used ahead of the spacer to reduce the hydrostatic and to allow the rate of 3 bpm to be used. One critical aspect to consider is the pressure differential of only 0.7 lb/gal (273 psi) across the gas zone after the end of the job. This illustrates the high potential for gas migration after cementing in slimholes. With this low differential, the pressures in the cement column and the gas zone could cross (during the cement transition time) before the cement has had time to develop enough gel strength to prevent gas invasion. If this happens, the wellbore would be invaded by the gas, unless the cement slurry was very well designed to control gas migration.

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Again, looking at all the simulation data, this is a case where good mud removal (and thus a good cement job) would be expected based on the optimization. However, there is danger for wellbore invasion after the cement job. The next step would be to design and use a good gas migration control slurry, and to try to do the job at the designed rates and with the optimized fluid properties, to obtain a good job. Let us now look at the effect of erodibility. The Figure below shows the effect that a different mud with an erodibility of 5 could have on the outcome of this job (PDG mud films with erodibilities of 5 or less are very hard to remove). Notice that with that erodibility, the spacer would have to be pumped at over 6 bpm to erode the PDG mud films. With that erodibility, none of the fluids would be capable of removing the PDG mud films. We already know, however, that those high rates would be prohibitive in this hole due to great potential for lost circulation. With the lower erodibility, if the job was done at 3 bpm, thick PDG films would likely be left against the permeable zones (great potential for poor zone isolation).

Figure 22: Lower Mud Erodibility Data for the 4-3/4"x 3-1/2" Annulus Erodibility Technology 4-37 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The Real World When it comes to cementing a well, the hole may present conditions that will help obtain a good cement job or the section may have elements that make obtaining a good cement job quite difficult. Benign hole A benign hole, from the point of view of cementing, has the following characteristics: • no potential for gas migration, • low temperatures, • constant hole size (gun barrel), • vertical configuration, • No dog-legs • not too long, • high fracture pressure, • reasonable low pore pressures, • non-reactive formations, • well centralized casing, • 3/4- 1-1/2” annular clearance (each side) • good mud properties, low gels • ability to move pipe • time allowed to condition the hole, etc. Difficult Hole A difficult hole presents the opposite of the conditions of the benign hole: • potential for gas migration, • high temperatures, • large washouts, • highly deviated, extended reach, horizontal hole, • deep, Rev. 01/2002


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• weak, unconsolidated, low fracture pressure formations • high pore pressures (narrow pore/frac window), • reactive formations, • poorly centralized casing, • narrow annular clearances, • poor mud properties, high gels, • unable to move pipe • no time allowed to condition the hole, etc. In the real world, holes to be cemented present a combination of favorable and unfavorable conditions. Because of this, sometimes compromises need to be made to balance the application of best practices with the available resources. Centralization, Hole Shape and Pressure Drop To generate the ECD data given in the slim hole example discussed above, the casing was assumed to be completely centralized. Perfectly centralized pipe produces higher frictional pressures than eccentric pipe. The ECD figure below shows the ECD's generated for the same slim hole situation, if the pipe was eccentric (against the wall). As can be seen, the calculated ECD's are much lower than for the centralized case. Obviously not centralizing the pipe to reduce frictional pressures is not an option because non-centralized pipe will cause channeling and a poor cement job. Additionally, in a real job, channeling would raise the hydrostatic pressure, potentially causing the total well pressures to be higher than for the centralized case.


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Figure 23: ECD's with 10 bbls Water - Pipe Eccentric Reactive Formations Hole sections containing reactive formations are often drilled with oil based fluids to minimize hole problems such as sloughing, large washouts, etc. Depending on the degree of reactivity of the formations, they may react when contacted with the water base spacer during the cementing operation. A few formations can be so reactive that they have been called 'explosive' when contacted with water. In the case of reactive formations, it is important to conduct tests in the laboratory using samples from the well (cuttings, cores) to carefully optimize the design of the spacer system. Cases have been documented where the use of 3 - 5% KCl in the spacer and the cement slurry have led to higher quality cement jobs.

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One thing that helps with this situation is that normally the length of time these reactive formations are contacted by the water base spacer and the cement slurry is very short when compared with the time needed to drill the hole section (a few hours vs. days). However, there are cases where the TOC places the spacer in open hole forever. Fluids Left Behind the Casing One issue associated with cementing of wells that is often ignored is the effect of the fluids left behind the casing after the cement job. Often cement is not circulated all the way to the surface, particularly when cementing the deeper strings in a well. Depending on the well conditions and the properties of the fluids in the annulus above the cement column, the fluids may tend to segregate, and potentially corrode the casing. Segregation/settling may lead to annular flow during the life of the well (loss of hydrostatic), if the fluid is across zones with potential for invasion of the annulus. Corrosive effects may eventually cause casing leaks at some point during the productive life of the well. Thus, all fluids left behind the pipe need to be examined to make sure they will not negatively affect the integrity of the casing strings during the life of the well. If WBM is to be left behind casing, the pH should be raised and, perhaps, an oxygen scavenger used. Fluid Contamination in the Casing A bottom plug has two main functions. One is to wipe the mud film from inside the casing wall ahead of the cement to prevent slurry contamination. If not used, the mud film may be wiped by the top plug, potentially displacing that volume of mud and contaminated cement into the shoe track. As an example, a 1/16" mud film in 15,000 ft of 7" casing amounts to 22.5 bbls of mud! Another function of the bottom plug is to separate the cement from the spacer to prevent mixing due to gravity effects while the fluids are going down the casing. Bottom cement plugs are available that use a rupture disk rather than a rubber diaphragm, to reduce concerns when using loss circulation materials. Under pressure differential, the disk breaks into small pieces. The potential for fluid contamination is greater with the larger casing strings. The larger the casing, the greater the potential for contamination in the casing if bottom plugs are not used. In practice, when pumping a large volume of lead slurry on a surface casing string, the bottom plug can be omitted. Plugs for large casing strings – eg 18 5/8” and above can be insufficiently robust to adequately perform Erodibility Technology 4-41 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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the job. Bottom plugs should be used whenever possible. Best cementing practices call for the use of several plugs. For example, one separating the mud from the spacer and another in between the spacer and the cement slurry. Shutdowns During the Cement Job Shut-downs are very detrimental to the success of cementing operations. The longer the shutdown to release plugs, switch lines or tanks, etc, the higher the potential negative impact on the job. Shutdowns cause gelation and dehydration of the drilling fluid in the hole. Therefore, every effort needs to be made to minimize or eliminate shutdowns during conditioning of the hole and during the cement job. To eliminate shutdowns to drop plugs, the industry has developed several versions of cementing heads that allow dropping of plugs "on the fly”. Displacement Volumes Quite often the service company's job monitoring devices (see On Site Data Collection below) are not connected to the output of the rig pump. One serious effect of this is that no permanent record of the job is collected when displacement is done with the rig pumps. In addition, if the assumed efficiency of the rig pump is not correct, the displacement volume may be in error. Where accurate displacement volumes are needed then the cementing unit should be used. Job Monitoring Proper monitoring of the job, comparing the measured against the predicted behavior, can assist tremendously in deciding if the well is experiencing loss circulation. Additionally, a permanent, continuous job record is essential to be able to perform a valid post-job evaluation to determine the causes of job failure. Cementing in Narrow Annuli Cementing in narrow annuli (slimholes) is not inherently different from conventional hole, primary cementing processes. Cement Slurry Design - The cement slurries used in slimholes must have some very special properties. For example, the slurries must have rheologies low enough such that they can be mixed and pumped at reasonable rates without causing breakdown due to excessive ECDs in the narrow annuli, but without exhibiting stability problems. In addition, the slurries need to contribute to properly displacing the drilling fluid from the annulus without dropping solids, particularly in deviated configurations. The narrow configurations generally dictate that the slurries need to have good fluid loss control and, in many instances, good gas migration control properties. Rev. 01/2002


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Slurry Placement - To take advantage of the erodibility technology, it is usually advantageous to pump at high annular rates for optimum displacement and to remove as much as possible of the partially dehydrated-gelled mud in the wellbore. Although smaller annular clearances increase the annular wall stresses for a given pump rate, there is also the problem of larger than conventional circulating pressures generated by the high rates. This leads to elevated equivalent circulating densities (ECDs) and the possibility of lost circulation. Thus, the proper design (fluids' rheologies, pump rates, etc.) for pre-job hole conditioning and cement slurry placement is one of the most critical aspects to successful cementing in a slimhole. Operational Issues - Slimhole drilling leads to the use of much smaller slurry volumes for cementing. This helps keep down the overall cost of the job, but also means more time and effort spent in the cement slurry design and testing phase, and special care during cement mixing and displacement. Due to the small cement slurry volumes used, even small amounts of contamination while mixing/displacing the cement slurry may dramatically affect the properties of the cement such as the thickening time, strength development and the WOC time. The narrow annuli also means that the volumes of spacers and washes must be carefully designed to make sure adequate annular coverage and fluids separation takes place during the job. In addition, volumes of un-weighted washes (flushes) need to be carefully designed with the assistance of job simulators to ensure well control is maintained during the cementing operation. Gas Migration - Due to small annular clearances and possible low overbalance pressures, potential for gas migration after cementing in slimholes is often significant. A slimhole may require more specialized gas migration control cement slurry design and field practices than a conventional well at the same depth. The specific hole to be cemented needs to be analyzed in detail and the cement slurries used need to meet critical gas migration control criteria verified by laboratory testing. Pressure Drop Across Liner Hangers and Polished Bore Receptacles Attention needs to be given to the configuration (OD's) of liner hangers and PBR's in relation to the ID on the previous casing, when preparing for liner cementing operations. Very large pressure drops can be generated across these tools if the annular clearances are narrow. This can cause a "piston effect" when running the liner, potentially fracturing exposed weak formations. Surge/swab simulators need to be used to check the configurations and/or to decide on the casing running speeds to avoid well damage. High pressure drops across liner hangers and PBR's are bad enough. However, the worst potential problem is the bridging of the narrow clearances across the tools. Bridging can easily occur from cuttings and/or other particles present in the well fluids even after hole conditioning. Hole cleaning and mud conditioning prior to running pipe is the key to success. Erodibility Technology 4-43 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Liner Top Packers Liner top packers are frequently used to provide a seal at the top of liners. They may be run either as an integral liner top packer; in which case setting takes place at the end of the job prior to pulling out with the running tool. Alternatively, they are run on a separate trip. Integral packers have become popular because they avoid the need to drill cement from the top of liner. Immediately following the job the packer is set and cement is reversed out. The packer avoids transmitting the hydrostatic pressure to the annulus which could lead to formation fracture. The use of such integral liner top packers needs to be carefully considered, particularly when permeable zones of unequal pressure are covered by the liner. If the packer is set soon after completion of the cement job, and assuming packer doesn’t leak, it then effectively shuts off the hydrostatic head on the cement column in the annulus. As fluid is lost from the cement slurry below the packer (inner shrinkage due to hydration), a pressure drop will occur in the unset cement column, greatly increasing the potential for fluids invasion. The end effect is that gas is trapped below the liner top and is often apparent on USIT logs. This may be detrimental later on in the life of the well. Zones of unequal pressure may cross-flow. Reverse Circulating Cementing Reverse circulation cementing has been used in relatively shallow wells (around 2,500 ft), but some applications have been reported to depths near 9,000 ft. It has also been used to cement tie-back strings. Reverse circulation cementing is performed by taking returns through the casing. A stab-in inner string can be used to hold a float shoe open and allow reverse circulation. The valve closes when the inner string is un-stung at the end of the cement job. Reverse circulation cementing may be a very viable alternative to conventional cementing practices in situations where weak formations may be broken down during normal cementing. Reverse circulation cementing may generate much lower job pressures across the open hole in slimhole cementing. Some float equipment has been developed to allow such reverse jobs without the need for an inner string, extending the potential application to deeper casing strings. There are many objections to Reverse Circulation Cementing, e.g: • Unconventional • Conventional float equipment cannot be used. Rev. 01/2002


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• Not possible to clearly tell when the job is finished (since there is no top plug, there is no clear pressure increase at the end of the job) • Concerns about the quality of the cement around the shoe. • Hole conditioning in the reverse circulation mode • Mud Displacement Efficiency • Well control issues • Casing collapse Main advantages of reverse circulation cementing: • Lower placement pressures across the lower weak zones during hole conditioning and cementing. • Lower placement pressures allow faster placement rates • Shorter cement jobs because the cement slurry is pumped down the annulus instead of being pumped down the casing and up the annulus. • Not all of the cement slurry sees high well temperatures found near the bottom of the well. In addition, placement times are shorter as indicated above. This may lead to cheaper cement slurry designs. Careful computer simulation is required to investigate the pressure drops and pressures likely to be seen during such jobs. The effect of geometry must be investigated. Liner Cementing Considerations Aspects that differentiate liner cementing from conventional primary cementing include: • Hole/annular size • Frequent requirement for good cement all the way into the lap • Often deeper and hotter • Equipment issues • Frequently need good mud removal & isolation – productive zones exposed Hole Size Annular clearance impacts the success of cementing operations. Studies have indicated that the best results are obtained with annular clearances of 1 to1 ½ Erodibility Technology 4-45 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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inches. Depending on well configuration and mud properties, large annular clearances may be detrimental to success, if at reasonable pump rates, not enough stress can be applied to remove gelled mud. With liners, annular clearances are normally small. In many liner applications annular clearances are ¾ " or less. Many successful liner operations have been performed with clearances of ¾ " (for example 7" casing in 8 ½ " hole) but in many cases caliper logs shown holes larger than 8 ½ ". When annular clearances fall below ¾ ", the cementing success ratio falls. Even getting the liner to bottom within the pore/frac window may be difficult. Centralization is a challenge and the use of very expensive centralizer subs may be necessary. An alternative is to under-ream the hole. Temperature Considerations In cementing full strings of casing, the cement performance concerns are mainly across the producing zones near the shoe. On liners, the cement must also set and seal at the top of the liner, which may be several thousand feet up the hole. The static formation temperature at the top of the liner may be much lower than the circulating temperature at the bottom. Therefore, an accurate understanding of the well temperatures is necessary for designing the cement slurry. Mud Removal Mud removal and avoidance of channeling are vital. Experience has shown that the chance of sealing the overlap is improved if excess cement, sufficient to fill about 500 ft of the drillpipe/casing annulus, is used. This excess volume can contribute to removal of the mud from the overlap and is normally sufficient to ensure all the contaminated cement slurry is out of the overlap. Sufficient spacer volume should be used to give a contact time of about 10 minutes. Another ‘rule of thumb’ is to use enough volume to provide about 800 ft of annular length to assist with mud removal. Weighted spacer should be mixed at a density between that of the cement and the mud. If the mud is oil based, the spacer formulation must contain surfactants to water wet the pipe. The spacer should not exhibit settling which could cause the drill pipe and running tool to get stuck above the liner top. It the liner is to be hung prior to cementing, it is a good practice not to set the liner hanger until bottoms-up have been circulated above the liner top. Setting the liner can reduce the flow path by as much as seventy percent. Debris can bridge this restriction and cause loss of returns. Rev. 01/2002


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Liner Equipment Detailed equipment information is given in another section of this manual. Here we will only briefly review this topic. In most liner cementing operations, a float shoe, a float collar and a landing collar are used. The use of redundant floats is to provide backup to prevent flow back of the cement slurry into the liner at the end of the job (U-tube effect). Some liner shoes incorporate multiple floats as an added safety measure. At least two joints of casing should be used for the shoe track, so that any contaminated cement slurry will be left in the liner rather than around the shoe. Liners should be centralized whenever possible. The difficulties in obtaining adequate cement coverage in liner applications due to narrow annuli is tremendously aggravated if the liner is not centered in the hole. Expensive solid blade or bow centralizer subs may be the only way to centralize the pipe in very narrow configurations (3/4 inch or less). These sub-type centralizers are made up as part of the casing string. Job Execution Movement of the pipe should be incorporated whenever possible. If it is not feasible to move the pipe during cementing, the pipe should be moved while conditioning the mud. Overlap Length In shallow, low pressure well situations, relatively short liner overlaps (300-400 feet) may be adequate to provide an effective seal. In deep, high pressure gas wells overlaps of 450 to 800 feet may be required. It has been reported that overlap lengths of less than 300 feet require more remedial cementing than overlap lengths of more than 450 feet. More on Liner Overlap Seal Two methods are used by the industry to obtain an hydraulic seal at the liner top with cement: • single stage • planned squeeze When using single stage cementing, the cement slurry is circulated around the shoe, up the hole and through the liner lap. If a planned squeeze is used, the slurry is circulated to a pre-determined point below the liner top and the liner top is then squeezed during a second operation. This approach is used when the formaErodibility Technology 4-47 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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tion cannot support the ECD developed during placement. Squeezing the liner top may require another trip. Whenever possible, the single stage method should be preferred. The advantages of the single-step method are: • A continuous sheath of cement may be placed all around and along the entire length of the liner. • No length of uncemented casing is exposed, in the life of the well, to high formation pressures, potentially corrosive fluids, point loading, etc. • The technique is normally less costly. Eliminates the need for another trip, longer rig times, etc. Post Job Testing and Evaluation The integrity of the cement seal in the overlap needs to be verified before a liner job can be considered a success. Before this overlap seal can be tested, the cement inside the previous string above the top of the liner must be cleaned out. In the ideal case, hard cement is drilled above the liner top. It is possible to obtain an overlap seal without encountering hard cement above the liner top. Normally, however, this is the exception rather than the rule. Many operators clean the liner out to the float collar prior to pressure testing the liner top for fear of collapsing the liner during liner top testing. If the liner top is to be tested before the liner has been cleaned out, the maximum load to be applied to the liner should be calculated and compared against the liner collapse rating. Testing of the overlap seal should not be done until the cement at the top of the liner has set and developed a predetermined amount of strength (normally about 500 psi). Compressive strength tests in the cement laboratory prior to the job will indicate the waiting time necessary for the cement to attain the desired strength. On long liners where the circulating temperature at the shoe may be much hotter that the static temperature at the liner top, extended WOC times may be necessary. Operators on expensive offshore rigs sometimes attempt to shorten these long WOC times by reentering too soon, only to lose several days to squeeze operations. To decide on the test pressure of the liner overlap, several approaches and considerations are available: • The maximum test pressure must not exceed the burst strengths of the affected casings. • Pressures to be used during the leak-off test at the liner shoe need to be considered. • It may be necessary to exceed the fracture limit of the zones near the previous casing shoe in order to determine if there is a seal. Rev. 01/2002


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• Sufficient test pressure should be applied to make sure further drilling operations are not impaired. • When drill stem or other testing is to be performed on lower zones, the overlap test pressure needs to be above the pressure needed in the annulus to operate the downhole test tools. • Pressures encountered in production or stimulation operations must also be considered. The permeability of a formation and micro channels in the cement sheath allow, in many cases, the flow of fluids in one direction, while restricting flow in the opposite direction. This may also be caused by debris in the overlap that may act like flow-check valves. If this conditions exists, it is possible to obtain a sufficient positive pressure test and still have gas flow into the wellbore. For this reason, it is always prudent to also conduct a negative test. This test is sometimes called a dry test or a differential test. It involves the relief of a portion of the well hydrostatic pressure in the wellbore. A retrievable squeeze packer is generally used for a negative test but a drillable packer can also be used. The packer is run in the hole on a work string (usually drillpipe), to a depth above the top of the liner. After setting the packer and conducting a positive pressure test, the bypass circulating valve on the packer is opened and drill water or diesel is pumped into the drillpipe, displacing the well fluid until a sufficient differential pressure is obtained. With the valve closed and the packer set to isolate the well fluid in the annulus, the differential pressure is bled off leaving the hydrostatic pressure of the fluid contained in the drillpipe on the liner top. Flow back is monitored to determine if a leak is present. After 15 to 30 minutes with no flow, the drillpipe is then re-pressured to the amount of the differential. The packer valve is opened again and the light fluid in the drillpipe is reversed out and again replaced with well fluid. The expansion of cool water after placement in a hot well will cause some flow and this should not be confused with actual well flow. A sufficient amount of differential would be the equivalent to the expected lightest hydrostatic to be incurred during subsequent drilling and eventual production operations. If this value is unknown, a 2000 psi differential is usually adequate. In all cases, compliance must be made with all local regulatory bodies in the running, cementing, and testing of liners. Liner Tiebacks Liner tiebacks to surface or liner stubs may be necessary at some point in the life of the well. Thus a tieback receptacle or sleeve is often run with the liner hanger. When running a tieback string of casing to the surface, a float collar and two plugs Erodibility Technology 4-49 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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should be used. Only one plug is used probably 80 percent of the times when cementing tieback strings to surface. As pointed out before, in large casing strings, if a bottom plug is not used, severe channeling inside the casing can occur, and a large portion of the cement slurry can become contaminated. A fluted mill should be used to dress the tieback sleeve prior to running in the hole with the tieback casing string. Many operators want to make sure the tieback stem is stabbed into the tieback sleeve prior to cementing. However, it is possible that the stem is pumped out during the cementing process due to the cooling effect of the circulated fluids. In order to protect the seals on the tieback stem, the pressure should be released and the surface left open when lowering the stem into the tieback sleeve. If the tieback stem seals fail, pressure needs to be held on the casing until the cement sets.

On Site Data Collection The minimum data to be collected continuously during the job is: Density of all Fluids Pumped The slurry density is the only continuous data that helps ensure that fluids are pumped as designed - particularly the cement. The slurry density data is critical for analyzing the quality of the cementing operation even if the slurry is batch mixed. This information should be recorded continuously using an on-site computer system. The Pump Rate The flow rate data helps estimate the displacement efficiency of the cementing job. To maximise displacement, the spacer and cement slurry must be pumped at the designed flow rates. In addition, the pump rate data can help with the calculation of the volume of the cement slurry placed in the well. This volume of cement pumped into the well is critical to analyze the cement tops and the possibility of channeling (along with the job pressures The Surface Pressure The job pressures are critical for the analysis of the cementing success. The pressure can provide a good idea of the circulating hole volumes, as well as to point out problems during the circulation of the cement like channeling, lost circulation, etc. Rev. 01/2002


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Service Company Cementing Software Software Introduction This Section includes service company descriptions of their cementing job computer simulators.

Schlumberger CemCADE Computer-Aided Design and Evaluation for Cementing CemCADE simulates a set of pumping conditions in a given well, but it is much more than a mere U-tube simulator. CemCADE is fully integrated software containing different modules where all aspects of a cement job are accounted for. Dynamic graphics are automatically updated with any change of data and a number of independent calculators further help the user selecting the appropriate cementing job parameters. U-tube and placement The U-tube simulator is an analytical tool, which calculates free-fall and ECD using the rheology of fluids at the temperature selected by the user (see Laboratory database). This is normally the temperature output by the temperature simulator. This U-tube simulator has been validated against field measurements where return flow was measured. The user inputs the different fluids, either by volume, or height (fill-up), or dynamically on the graphics. A comprehensive set of graphs is selectable. Pauses in the pumping schedule can be included at any stage in order for the U-tube simulator to realistically simulate the movement of fluids during events such as dropping plug, switching tanks or silos… Output can be selected versus time or volume. Service Company Cementing Software 4-51 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The user is then able to easily verify that the well is kept under control at all times during the cement job (no loss-no gain situation). CemCADE simulates any kind of cement job: primary casing, liner, 1st, 2nd or 3rd stage, stab-in, offshore with or without riser (and air gap), tie-back liner, tie-back casing… In the case of a liner, CemCADE also simulates circulation of excess cement above the hanger, after the cementing operation, if a liner packer does not exist to prevent transmission of applied annular circulation pressure through the cemented annulus. Input data In order to achieve this first objective of well control, CemCADE is fully integrated in the Drilling Office software suite. Not only can CemCADE read full survey and caliper data (imported as ASCII files), but this well data can be automatically downloaded from the Drilling Office database. Hence these caliper and survey tables can have several hundred lines of data. A pipe database is available, but the user can define his own casing and drill pipe strings. Formation description (rock and fluid types, pore and frac pressures) is also described in a table containing as many lines as information is available. This data is used for the pressure checks made whilst simulating the cementing operation, as well as for the temperature simulator and the Post-Placement analysis. Fluid database CemCADE is fully coupled to the LabDB fluid laboratory database, where fluid data can be searched locally as well as through the network. All tests for given slurry are automatically retrieved. Rheology is measured at different temperatures. The user then selects the rheology, which will be used in the simulations: he would particularly choose the rheological parameters measured at the temperature closest to the one given by the temperature simulator.

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Centralizer CemCADE contains a centralizer database, but the user can define his own centralizers. Different types of centralizers (rigid, bow, semi-rigid…) can be combined at will. Centralization is calculated for a given distribution of centralizers, or the simulator proposes a distribution in order to achieve a given minimum desired standoff. The standoff is calculated not only at the centralizer, but also between centralizers, in order to account for the deflection of the beam under its own weight. Drag force while running the casing with the selected distribution of centralizers is calculated in order to verify that the casing will run to bottom. Mud Removal Design A number of independent calculators help the selection of the proper properties for the fluids pumped, so that each fluid will effectively displace the preceding one in the chosen flow regime, as a function of eccentricity, deviation, hole size… The criteria must fulfill the WELLCLEAN eccentered mud removal technology. Once the fluid properties have been selected, the U-tube simulator and the centralization calculations are run. The Mud Removal simulator will then output the efficiency (versus depth, and time for turbulent flow or volume for Effective Laminar Flow) at which the preflushes displace the drilling fluid, and the slurries displace the preflushes. Aids for Design of Effective Laminar Flow Displacement This module helps the user selecting dynamically and graphically the optimum properties for the displacing fluid for efficiently removing the displaced one, as a function of annular geometry, deviation and pipe standoff. Evaluation of the Mud Displacement Process A 2-D numerical simulator visualizes the fluid displacement. Channels and films on walls are identified. Primarily an evaluation tool, this simulator can be used in design mode. Cement Job Evaluation CBL Adviser The CBL Adviser module helps in evaluating cement bond logs, accounting for all well parameters and outputs the referenced CBL amplitude for the given cementing operation. Service Company Cementing Software 4-53 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Post-Job Evaluation CemCADE uses the recorded job data to simulate all the operation using these job parameters. This simulation of the operation using the execution data allows to identify problems that occurred during the operation, by comparing the Job Signature with the simulated curves. Typical problems are hole instability and annular closure, fluid channeling and losses. Subsequent cementing operations can therefore take into account the occurrence of such events, and the design can be modified accordingly. Temperature Simulator In addition to handling multiple temperature gradients, this analytical tool accounts for well deviation, annular geometry, type of formations, fluid rheologies and flow regime. Above all, pump rate and time are key factors in these heat transfer phenomena. CemCADE’s temperature simulator was validated by field measurements made in the early 1990s in onshore and shallow offshore wells. CemCADE temperature simulator has now been validated in deep water conditions and requires the input of the temperature profile and the current profile in the column of sea water. Temperature simulators are therefore recommended when well conditions deviate from vertical or when a particular pumping schedule is planned to cool the well, or in deep water wells, as the API schedules cannot handle these situations. The output of the temperature simulator is used for the laboratory to optimize the fluid properties. It is used also to recommend, particularly in HP-HT wells, a minimum circulation period prior to cementing not only for cleaning the wellbore, but also for establishing a flat temperature profile versus depth. This ensures that all the fluids pumped will keep their properties as designed. Plug Cementing A plug cementing module helps designing the conditions for increasing the effectiveness of placing cement plugs off bottom. This tool recommends a certain rheology for the fluids in order to prevent the instability of the plug after placement, due to both fluid swapping in vertical and deviated wells and to slumping in highly inclined wellbores. The placement of the cement plug is also carefully considered in order to optimize mud removal and avoid overdisplacing the fluids, particularly when using tapered strings. Recommendations are for fluid volumes and rates in order to keep stable interfaces between each fluid, inside and outside the drill pipe, and after having pulled the pipe. Rev. 01/2002


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NOTE ON MUDPUSH: MUDPUSH XL applies the Effective Laminar Flow (ELF) technique, which combines several criteria to achieve optimum mud removal at low flow rates. For a long period of time, the oil industry has considered only two suitable flow regimes to achieve proper mud removal: Turbulent Flow and Sub-Laminar Flow (also called Plug Flow). The reason very often put forward for promoting Plug Flow and avoiding Laminar Flow is based on the confusion between the velocity profile of a given fluid and the interface profile between two fluids. Although the exact description of this interface is not yet fully known, it is recognized that, under certain conditions, the interface profile can be quite flat even in Laminar Flow. One of these conditions, which is also our first criterion of the Effective Laminar Flow technique, is the well-known Density Hierarchy between the Displaced and Displacing fluids. In other words, the slurry density must be higher than the spacer density, and in turn the spacer density must be higher than the mud density. As the density differential between the displaced and displacing fluids increases, their interfaces become flatter and more stable. A minimum density difference of 10% between the displaced and the displacing fluids is recommended. The second criterion that must be met concerns the Friction Pressure generated by the flow of the Displaced and Displacing fluids. To increase the stability of the interface, this criterion recommends that the friction pressure generated by the displacing fluid be greater than the friction pressure generated by the displaced fluid. This is equivalent to having, for a given annular geometry and flow rate, the apparent viscosity of the displaced fluid lower than the apparent viscosity of the displacing fluid. The third criterion, often referred to as the MPG (Minimum Pressure Gradient) criterion, verifies the mobility, in an eccentric annulus, of the displaced fluid providing this fluid exhibits a yield stress. The fourth and last criterion is called the Differential Velocity criterion. In an eccentric annulus, a single fluid will always flow faster on the wide side (the path of least resistance) than on the narrow side. This criterion imposes that the displacing fluid does not flow faster on the wide side of the annulus than the displaced fluid on the narrow side. These four criteria have been implemented within the CemCADE program and the acceptable range for annular flow is the output. For a given set of conditions, the minimum annular rate calculated by the CemCADE program equals the highest of the following values: • Minimum rate for MOBILITY on the narrow side of the casing for fluids exhibiting a yield stress (MPG criterion) • Beginning of the 20% friction pressure hierarchy • Arbitrary lower limit of 1 bbl/min Service Company Cementing Software 4-55 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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• Beginning of the stable front between the large and narrow sides of the casing (velocity criterion - optional). • The calculated maximum annular rate equals the lowest of the following values: • End of the 20% friction pressure hierarchy • Full establishment of turbulence by the displacing fluid (turbulent-flow placement should then be used) • Arbitrary upper limit of 40 bbl/min • End of the stable front between the large and narrow sides of the casing (velocity criterion - optional). The main parameters affecting these boundary rates are fluid rheologies and their densities, pipe and openhole geometry, pipe eccentricity, and well deviation. Within the MUDPUSH family (XT for Turbulent, XL for Laminar and XS for Salt Systems), the viscosifiers used are special products that enhance each system’s characteristic. The D149, for instance, allow a wide range of PV and Ty under different concentrations on the XL spacer, this behavior is not exactly found on other viscosifiers.

Halliburton OptiCem A Primary Cement Job Simulation Program OptiCem - is a primary cement job simulation program. Any type of primary job can be simulated. OptiCem takes into account all known cementing factors. Mud channeling, eccentricity, freefall, mud compressibility (inthe works), temperature dependant rheology, gas expansion and compression,change in viscosity with changing foam quality, Tuned Spacer, hookload, etc. Mud channeling OptiCem calculates the forces required to remove mud and then compares the required forces to the force present under the planned job scenario and predicts whether the mud will be removed or not based on these relative forces. Rev. 01/2002


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Eccentricity OptiCem can calculate frictional pressure losses based on concentric pipe or eccentric pipe. The standoff of the pipe for these pressure calculations can be entered as a single fixed number or be dynamically calculated based on the planned centralizer program. Thus the level of eccentricity is allowed to vary up and down the entire wellbore, if the design requires that level of accuracy. Freefall Freefall is important with the larger surface and conductor strings when cement enters the annulus, these strings may become buoyant. Prior knowledge of this is critical for the success of the job and the safety of those present on location. If the rig is near capacity do to string weight, knowing the maximum weight when the casing is full of cement is also critical for the success of the job and the safety of those present on location. Pressures acting on all shoulders, lateral forces, and drag stresses are all considered. Mud compressibility (in the works) Many of the new mud systems are compressible enough that there changes in both volume and density become significant. The next release will contain PVT correlation's for a minimum of 6 different base fluids and the algorithms that will change there volumes and densities as they move through the well-bore. Temperature dependant rheology OptiCem can use anything from a basic straight line temperature profile to the most sophisticated WellCat simulation as input. If a single rheology data point is entered that rheology will be applied to the entire wellbore. If rheology data is entered at two or more temperatures, OptiCem will thin the fluid on the way down the casing and then thicken it as it cools on the way up the annulus. These continually adjusted rheological parameters will be used to calculate the frictional pressure drops. Tuned Spacer OptiCem's Tuned Spacer wizard allows the user to tune the spacer's rheological properties to the given well conditions. If the properties are entered to match the well conditions, the tuning process will provide sufficient levels of shear at the wall to remove the gelled mud. Service Company Cementing Software 4-57 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Gas expansion and compression In foam cementing the gas must be allowed to expand and contract as the pressure and temperature changes. As the gas changes volume the internal flow rate will change in unison. As the foam quality increases the fluid density hydrostatic pressure decreases. OptiCem takes all of these factors into account when determining ECD. To properly design a foam job the N2 concentrations and base slurry volumes must be infinitely adjustable to allow the user to get the proper amount of down hole volume and the required density profile. To know how to adjust these parameters the user must know how much down hole volume results from the planned job process and what the final density profile will look like. OptiCem allows the users to easily adjust these data and provides the results required to correctly make these adjustments. Change in viscosity with changing foam quality As the foam quality increases so will the viscosity. To accurately model foam volumes and densities the user must accurately model pressures. OptiCem uses these adjusted rheologies to modify the frictional pressures. Hookload With large surface and conductor pipes after the heavy tail enters the annulus the pipe can become buoyant. If the pipe floats out of the well the job will be a failure and the safety of the rig personal will be at risk. When the hung pipe weight is near the rigs maximum the added weight of the cement might exceed the safe operating range for the rig. If the rig collapses, again the job will be a failure and the safety of the rig personal will be at risk. OptiCem takes into account the forces on all of the shoulders, the lateral forces, and the drag stresses.

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BJ CMFACTS Primary Cement Design, Analysis and Real-time Monitoring Program The following is intended to be a brief overview of the simulator methodology and features. The simulator calculations make some general assumptions. 1)

Base slurry properties remain constant (through shear/temperature changes).

2)

Temperature gradient (for foam calculations) is linear.

3)

Flow characteristics of a nitrified fluid can be extrapolated from the base fluid.

4)

The pipe is concentric and the fluids moves in plug flow with 100% mobility.

5)

Annular fluid volumes do not change to account for measured and calculated return rates.

The simulator tracks up to 300 fluid segments in the pipe and annulus. Fluid segments account for varying density and/or gas ratio. Pressure calculations are performed iteratively at certain time intervals. Input parameters are slurry rate in and slurry density in. Surface pressure at the wellbore is assumed, and pressures along the flow path are calculated, accounting for diameter changes, down the pipe and up the annulus. Iterations are performed until calculated return pressure is sufficiently close to the specified or measured value. If the iterations result in negative surface pressure, this is accounted for by free-fall. This will cause slurry rate out to be different from slurry rate in. Calculated pressure and return rate can be compared to the measured values, and calculated ECD's at critical depths can be studied to gain an insight into the job. Service Company Cementing Software 4-59 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Features 1)

Generalized wellbore geometry.

2)

Multiple fluid types (including multiple displacements).

3)

Returns at sea floor allowed.

4)

Newtonian, Power Law and Bingham Plastic fluid behavior.

5)

API Spec 10 flow regime and pressure drop calculations.

6)

Nitrogen or air foams.

7)

Variable displacement rates, including shut-downs

8)

Free-fall effect.

9)

Integrated graphics: including time based xy-plots, depth based ECD and Reynolds charts, wellbore diagram, fluid inventory, mud placement/displacement graphic etc.

10)

User can pause or slow down simulator and manually control key parameters (rate, density etc) for “what-if’ analysis.

11)

Tracks information (ECD, Reynolds) for critical depths.

12)

Design, post-job analysis and real-time modes.

13)

Allows plotting of design vs. actual surface pressure, return rate

14)

Mud displacement calculations are performed by the simulator but are not integrated into the flow calculations.

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Mud Preparation and Removal Introduction Mud has a critical role and will influence the performance of cementing operations. The mud will be responsible for the condition of the wellbore and the quality of the displacement to cement, which in turn will influence its long term. Good mud engineering will create the environment that will allow for the smooth installation of the casing or liner, the mud displacement and the quality of the cement seal and casing support.

Wellbore Conditioning While the displacement from mud to cement is critical, the condition of the wellbore in preparation for the cement is also extremely important. A conditioned wellbore will have been drilled with mud that has an efficient sealing capacity, which will have left a thin tough filter cake across all exposed formations. The mud will have been used with adequate flow rates and viscosities to ensure the hole is clean and all drilled cuttings and cavings have been removed. The directional drillers will have taken the bit to target leaving the hole with limited tortuosity and minimal doglegs. The filter cake is the man-made membrane formed behind the bit on the wall of porous formations. This membrane will contain a sample of all the solids in the mud and its thickness will reflect the relationship between the rock pore throat or fracture size and the particle size distribution of the mud. Formations with a large pore throat size and mud loaded with only very small particles will build a thick cake before the bore hole wall becomes impermeable. While mud that has a distribution of different sizes will form a seal more quickly, resulting in a thinner cake. This is applicable to all mud types. Displacements and cementing can be best achieved when they are featured throughout the drilling process. In the following table mud characteristics are explained with regard to the drilling and casing/cementing operations. Mud Preparation and Removal 4-61 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Figure 24: Mud Properties Mud Characteristic

Drilling Phase Benefits

Casing & Cementation Benefits

Sealing capacity “Filter cake design and properties that go beyond the conventional mud tests”

The mud should be designed to build the thin nest possible filter cake against all the differing porous formations, providing better trips, lower annular pressure drops and reduced risk of stuck pipe Filter cake construction should be matched to formations exposed and not only based on API low and high pressure tests carried out as part of the mud testing to provide wellbore stability

A thin filter cake will ensure minimal annular pressure loss. Thereby, allowing higher pump rates for a superior displacement. A thin/tough filter cake will prevent rapid unplanned dehydration of cement slurries, which could cause premature setting and erratic performance. A thin filter cake will enhance casing running. A thin filter cake will reduce the risk of differential sticking of the casing. A thinner filter cake will enhance the cement bond. An effective filter cake will maximise the benefits of the hydrostatic force and improve wellbore stability; a stable wellbore has fewer washouts.

Viscosity “Lower Plastic Viscosity and lower 30 minute gel strengths”

The mud is made viscous to facilitate cuttings transportation, this viscosity should be man aged to reduce the Plastic Viscosity and optimise the Yield Point and Yield Stress. Progressively increasing gel strengths - as measured between 10 seconds, 10 and 30 minutes - are detrimental to all operations. Gel strengths measured after 30 minutes should be reported throughout drilling operations with a maximum value set.

A low PV will enhance hole cleaning and a clean hole prior to cementing will reduce the risk of losses caused by a build up of solids in the wellbore. Mud with a lower PV require less energy to initiate flow and can therefore be moved more easily ahead of spacers and cement, facilitating its removal from a narrow annulus. Progressively increasing Gel strengths pre vent mud flow in washouts and take more pressure to initiate flow, resulting in channelling.

Solids Content “Low Gravity Drilled solids”

Poor size distribution and high volume will make viscosity more difficult to control. Poor size distribution and high volume spoil filter cake construction.

Low values of low gravity solids will help control PV and gels and allow for good mud removal. Low, appropriate values of low gravity solids will allow formation of thin, tight, filter cakes.

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Different Mud Types Drilling & Cementing with the same mud properties can be achieved, but will require that the highest standards be maintained. The engineer must specify the properties that are to be reported and agree with the contractor how much latitude is allowed, as slippage is inevitable. All fluids used to drill will deteriorate and it is this deterioration that must be controlled. The mud used to drill will be either oil or water based and there are important differences, which must be understood and taken into account during the planning process.

Cementing in Oil Based Mud (OBM) Viscosity Oil based muds derive limited viscosity from the base oil and submicron-sized emulsified water, but this viscosity will be Newtonian in character. The major non-Newtonian rheology is derived from organophilic clays (also known as organoclay). These are bentonites in which the inorganic exchangeable cations, such as sodium, calcium and magnesium, have been displaced by fatty quaternary amines. Low-Shear-Rate Viscosity

Generally, oil-based muds behave as pseudo plastic fluids. They thin with increasing shear in a manner similar to clay-containing water-based muds. However, absolute viscosities tend to be considerably lower in oil-based muds. A consequence of this is that oil-based muds generally do not suspend solids, such as weighting materials and drill cuttings, as well as similar viscosity water-based muds. This property is particularly important at low shear rates and is related to the low-shear viscosity and elastic properties of the mud. Drilled Solids

Since there is, as yet, no reliable method of removing colloidal size particles from oil-based muds, these solids tend to build up in the system, eventually affecting the mud properties. High plastic viscosity values and elevated low gravity solids content are indicators that the mud is contaminated. The longer the oil mud has been in use, the more colloidal size solids will have accumulated. Although removing solids with solids control equipment, particularly with the centrifuge, may help, colloidal solids cannot effectively be removed mechanically. In this case, Mud Preparation and Removal 4-63 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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dilution with base oil is the only recourse. Dilution can be minimised, however, with the use of a good solids control program to remove as many solids as possible before they degrade to colloidal size. Fortunately, oil mud does not allow degradation of the solids to occur as rapidly as it would in water-based mud. The Cement Job To assure a good cement job with oil-based mud, we recommend careful adherence to the principles outlined in this section. Some of the difficulties outlined below will help you understand why these measures are so important. Cement slurries and oil-based mud are extremely incompatible. These two fluids form very viscous masses when they come in contact with each other. The presence of these viscous masses makes the displacement of the mud from the hole during the cementing operation very difficult. Since most oil-based muds contain salt in the aqueous phase, any mud left in the hole and contaminating the cement slurry may significantly affect the thickening time of the cement. In a well drilled with stable water-in-oil emulsion mud the casing and the formation are preferentially oil-wet. Since cements do not bond to oily surfaces, it is necessary to reverse this preferential wetting. Oil-based muds tend to be run with lower gel strengths which contribute to better displacement, and finally, the good fluid loss control properties associated with oil-based muds generally produces a thin, firm filter cake which is also favourable to the displacement process.

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As mentioned above, the surfaces in wells drilled with oil-based muds are normally oil wet and cements will not bond to oil wet surfaces. We must do everything possible to assure that all of these surfaces are water-wet before the cement slurry contacts them. This factor makes flush/spacer design and placement a critical element in achieving a successful cement job in a well drilled with oil-based mud. Functions of Spacers and Pre-Flushes

The functions of spacers and pre-flushes are: • To effectively separate the cement slurry from the drilling mud during placement • To prevent the formation of thick viscous interfaces that are detrimental to the displacement process • To remove as much of the mud as possible, ahead of the cement slurry. • To treat the pipe and formation surfaces so that they are water-wet, rather than oil-wet, allowing an effective hydraulic bond to be established between the cement, the casing, and the formation. (The spacer fluids used must contain surfactants capable of water wetting the surfaces.) To maintain control of the well during the sweep/flush and cementing process. (Be sure that the density of the spacer/pre-flush does not reduce the total hydrostatic head sufficiently to allow a kick to occur.)

Cementing in Water Based Mud (WBM) As discussed above cement slurries and oil-based mud are extremely incompatible. While this is not so true for water-based mud, water based mud does present other problems. Cement contamination drastically changes the nature of freshwater, clay-based systems. The calcium ion tends to replace sodium ions on the clay surface through a Base Exchange. The bound layer of water on the clay platelets is reduced, resulting in diminished hydration or swelling characteristics. The effect of calcium contamination on deflocculated muds is increased fluid loss, yield point and gel strengths.


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The potential for contamination during the displacement must be a prime concern and time must be allocated for a final treatment of the mud prior to cementing. This treatment will be to reduce the viscosity, with particular attention to the gel strengths. The 10-minute gel strengths should not exceed 35-lb/100ft2. If a treatment is required it may take the form of a dilution, but when minimal disturbance to filtrate control and inhibition is required, a treatment with an approved deflocculant such as: • Chrome free Lignosulfonate (1 to 4 ppb 3 to 11 kg/m3) • DESCO® (1 to 4 ppb 3 to 11 kg/m3) • Drill-Thin® (0.1 to 0.5 ppb 0.3 to 2 kg/m3) • Other proprietary WBM thinner is advised.

Contnation of WBM with Cement In the case of cement contamination, diagnosis is usually simplified by the fact that we know ahead of time when we will be drilling cement. The physical and chemical indications of lime or cement contamination are; increased yield point and fluid loss, increased pH and alkalinities, and a possible increase in calcium. The calcium increase may be masked, however, by pH. Gypsum and anhydrite contamination is also characterised by an increase in yield point and fluid loss, as these effects are the result of the divalent cation (Ca ++) in the mud. Alkalinities and pH decrease with anhydrite contamination because CaSO4 and H2O liberate H + ions. An increase in detectable Ca ++ is also likely since there is not a high pH to limit its solubility. Approximately 100 mg/L of Ca ++ should be left in the system to react with carbonate ions. In most drilling operations, cement contamination occurs one or more times when casing strings are cemented and the plugs are drilled out. The extent of contamination and its effect on mud properties depends on several factors. These include solids content, type and concentration, deflocculants, and the quantity of cement incorporated. One 94-lb sack of cement can yield 74 lb of lime. When cement is completely cured only about 10% is available whereas, when it is soft (green) as much as 50% of the lime may be available to react. It is the calcium hydroxide (lime) in cement, reacting with solids, that causes most of the difficulty associated with cement contamination. Rev. 01/2002


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Viscosity Freshwater bentonite systems are flocculated by cement, resulting in increased viscosity and fluid loss. The severity of flocculation depends upon the quantity and quality of solids present and the solubility of the Ca++ ion. The major contributor to viscosity will be either hydrated clays and/or polymers. The suspension will be in either fresh or low to medium salinity brine. In most cases the suspension will be sensitive to cement as it contains high concentrations of calcium and hydroxide ions, both can be detrimental. Calcium will cause flocculation of clays while elevated pH (>11.5) will cause the degradation of most viscosifying polymers. Drilled Solids Excess solids are by far the most prevalent and detrimental to all types of muds. Solids problems are often magnified by the presence of other contaminants such as cement, because excess solids and contaminant ions can strongly interact to create a more serious mud problem than either one separately. High plastic viscosity values and elevated low gravity solids content are indicators that the mud is contaminated. Although removing solids with solids control equipment, particularly with the centrifuge, may help, colloidal solids cannot effectively be removed mechanically. In this case, dilution with either water/brine or whole mud is required. Dilution can be minimised, however, with the use of a good solids control program to remove as many solids as possible before they degrade to colloidal size (see section on solids control). Unfortunately, water does allow degradation of the solids to occur as rapidly, unlike oil based mud. The Cement Job

To assure a good cement job with water-based mud, we recommend careful adherence to the principles outlined in this section.


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Cement slurries and water-based muds are incompatible, but unlike OBM where the two fluids will form a very viscous interface when they come in contact with each other, most WBM’s will not interact so severely. It is only WBM’s containing high clay content and has not been properly prepared which will become viscous. Such a viscous mass makes the displacement of clay/solids laden mud from the hole during the cementing operation difficult. Some water-based mud contain salt, therefore, any mud left in the hole and contaminating the cement slurry may significantly effect the thickening time of the cement. In a well drilled with water-based mud, the casing and the formation will remain water-wet and present no problems with regard to wettability. Water-based muds tend to be run with higher gel strengths which contributes to poor displacement, and finally, the fluid loss control properties associated with water-based muds generally produce a thick, soft filter cake which is also unfavourable to the displacement process. The advantages of being able to displace to a hole filled with water-based are:

• The effects of contamination to the mud can be controlled • Contamination to the cement is minimal The disadvantages of being able to displace to a hole drilled with water-based are:

• Inferior wellbore condition • Poor wall cake condition • Higher gel strengths Functions Of Spacers and Pre-Flushes The functions of spacers and pre-flushes are: To effectively separate the cement slurry from the drilling mud during placement, to prevent the formation of thick viscous interfaces that are detrimental to the displacement process and to remove as much of the mud as possible, ahead of the cement slurry. To maintain control of the well during the sweep/flush and cementing process. (Be sure that the density of the spacer/pre-flush does not reduce the total hydrostatic head sufficiently to allow a kick to occur.) Rev. 01/2002


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Engineering Recommendations If the correct pre-emptive actions are taken during each phase of well construction, it is possible to use mud to optimise both drilling and cementing operations. The following checklist is designed to help ensure nothing is left to chance. Planning Phase

• When establishing the mud type to be used for drilling, review and itemise the properties critical for cementing.

• Include a section in the Mud and Well Programme that will state the optimum properties needed for the displacement. Ensure that the 30-minute gel strength is included in the daily mud report.

• Establish a reporting process to ensure the Operations Drilling Engineer, Mud Contractor, Drilling Supervisor, Cementing Contractor and Drilling Superintendent are all aware of the critical cementing properties during drilling. Drilling Phase

• Monitor and maintain the programmed properties needed for the wellbore and displacement.

• Ensure the reporting process is maintained and those all concerned understand the consequences of any slippage from the predetermined properties.

• Establish a contingency plan for the predicted wellbore condition and the prevailing mud properties. If drilling conditions have required the mud properties to deviate from the programme, priorities for the cementing and casing operations may have changed. Discuss the changing situation with the mud and cement contractor more frequently and establish a new strategy for the cementing operations. Inclusion of the Mud & Cement contractors as early as possible when drilling conditions deviate from the plan, will lead to a better prepared cementing operation. • Prepare a plan for the displacement. Ensure adequate pit space for the spacers, contaminated returns. Arrange transportation for removal from site of excess or unwanted liquids.

• Determine when time will be available for circulating and condition the mud. Find out…

•

“How much scope there will be for circulation and treatment while drilling the last few feet and prior to tripping to run casing?” “Will circulation occur Mud Preparation and Removal 4-69 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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only prior to running casing or will it be possible to circulate with the casing on bottom?”

•

“Estimate how much time will be needed to condition the mud to optimum properties for displacement?” “How much time can be spent circulating when the bit reaches TD?”

• •

“What mud properties can be altered to meet the required specification?” Require the Cement and Mud Contractor to collaborate in the analysis of the predicted viscosity and density of the mud and the predicted displacement conditions. Use all available data to establish if additional conditioning is required and the pressure profile to be expected during the displacement. Use all available Hydraulic Modelling devices with various scenarios to prepare for all possible mud and wellbore conditions.

• Review drilling operations to determine the risk of subsurface losses during the cementation. Establish a plan to ensure there is sufficient mud to complete the displacement, if losses occur and mud returns are limited.

•

Any loss of mud returns that occur during the cementing operations will effect of the quality of the job. An accurate account of all volumes must be made at the start of operations, with the anticipated volume gains from the cement and spacers recorded. The anticipated pump rates used to pump spacers, cement and the displacement must be known by the mud loggers and the mud engineer. The mud engineer and loggers must be given the responsibility of collecting this data. This information will allow any changes top-of-cement to be calculated and an action plan to be implemented.

• Assess potential for an environmental incident during the cementation. Cementing Phase • Ask the Cement and Mud Contractors to collaborate in the analysis of the wellbore condition and diameter. Various techniques can be used without the need of a calliper; to aid in the establishing the volume of cement required needed to reach the required TOC. The volume of mud used to drill the section can be used to calculate an accurate estima tion of the open hole size. Mass Balance calculations using the retained low gravity solids content, dilution volumes and the efficiency of the solids control equipment can be made to provide accurate infor mation. This technique has proved to be within 10% of the actual hole size. This process is extremely useful when cementing in areas that experience wellbore insta bility.

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• Minimise the delays between the last circulation and the cement job. • If using WBM determine if the mud being used to displace the cement should be treated in advance of the cementation for possible cement contamination. • Mud left in the hole behind casing may have more value being reused and it may be viable to displace it and have it replaced by a less valuable mud. This will need to be determined on a case by case basis.

A fte r tim e a n d u n d e r c erta in d o w n h o le c o n d itio n s , th e o rg a n ic m a te ria l fo u n d in W B M w ill d eg ra d e a n d H 2 S c an ac c u m u late . P u m p in g m ud tha t co n ta in s n o o rg an ic m a te ria l i.e . B e n to n ite , b arite a n d w ater, a h ea d o f the ce m e n t ca n p re ve n t this p ro b lem . H2 S sc a v en g e rs c a n b e ad d ed if re q u ire d .

• Mud left in the hole behind casing may be the cause of future corrosion. Therefore, have the mud contractor treat the mud system during the final circulation. The treatment could include: Increase the pH Reduce dissolved oxygen • Check the proposed Cement Spacer formulation for: If any of the exposed formations are reactive to uninhibited mud, they could be sensitive to the spacer. The exposed formations may be sensitive to small changes in hydrostatic pressure. Ensure wellbore stability and pore pressures remain unaffected by the spacer density or chemistry. -

-

-

Spacer viscosity and annular velocities ahead of the cement may need to be compared with those used during the drilling phase. The hole cleaning performance of the spacer and cement may be improved to such a degree that cuttings previously undisturbed may be moved, creating a potential pack-off at any restriction, such as the liner hanger. If the spacer design calls for the use of barite, ensure the initial viscosity is sufficient for its suspension.


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Summary A great deal of effort will have gone into drilling the hole and the mud will have played a critical role, but this is only its first job. For successful completion of the well the mud will have to make way for the cement and protect the casing. To construct the well, the properties needed for a good cementation must be part of the daily assessment of mud performance. The API low and high pressure fluid loss tests performed as part of the mud engineer’s tests, will detect variations in the capacity for the mud to seal, but uses a low porosity filter paper, which may or may not reflect the mud’s true sealing capacity. It is recommended that a Permeability Plugging Test (PPT) be incorporated as part of the mud testing and that an aloxite disk of the required permeability be used when high permeability and/or high overbalance are predicted.

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Section 5: Cementing Operations Design Process

Design Process Aims: Optimising the cementing process by addressing: •

Well and cementing objectives

•

Risk identification and management

•

People competency

•

Learning

Understand the requirements for Cementing Documentation: •

Cementing Basis of Design

•

Cementing Risk Register

•

Cementing Program

•

End of Well Review

Introduction Much has been said elsewhere in this manual about the need for planning, for achieving good mud properties, for a slurry design with the optimum properties. This section will look at assurance processes and how to engage, not just the cementing contractor, but also others who can make a difference to the success and quality of the job. The importance of the mud contractor as been repeatedly stressed. Mud, unlike cement, is run as a dynamic, continuously changing process. The properties are monitored, adjusted and the fluid is re-run around the system. Cement is a ‘one-shot’ process with no second chance. At best, a squeeze job is a time consuming exercise. Often, it is less than satisfactory on a ‘life of well’ basis. Cementing Operations Design Process 5-1 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Everything, therefore, needs to be done to ensure that the first attempt is the very best possible job. You can’t fix it on the run. The planning has to be of the very highest standard. Traditionally, the cementing service company has supplied the cement, chemicals, pumping equipment and personnel. Their main responsibility used to be seen as providing the slurry and the capability to pump it into place. Poor quality cement, poor quality additives and a casual approach to lab. testing led to ‘train-wreck’ jobs, junked wells and considerable frustration for the operator’s drillers. You will have seen throughout this manual the multidisciplinary aspects involved in getting the best quality job. The best slurry available, with the very best cement and chemicals, will not give good zone isolation across a washed-out hole section full of gelled mud. Nor will an eccentered casing string in a gun-barrel hole, if the spacer and cement are not pumped in an engineered manner which specifically addresses the complexity of the fluid rheologies. Some surprisingly simple steps are often overlooked in the general drilling engineering planning. Sometimes the service company engineer will not give due thought to an aspect of the job because he feels that it is out of his hands. He is sometimes encouraged by the drilling engineer into this thinking because he is concentrating on other aspects of the well. The cementing engineer asks the mud company for the mud properties and gets what the mud company thinks they should be, rather than what they will actually be. The cementing engineer sees no particular problem with the mud and, anyway sees his job as getting the slurry design and logistics sorted. On the rig the cementers see their job as mixing the slurry and pumping it without mishap. The mud engineer is glad to have reached section TD with the mud in some reasonable shape and is little concerned about the cement job other than how it will affect his pit space management. Add to this scenario that nobody has been particularly concerned about centralization and you can find plenty of reasons why the job is not likely to be a success.

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This provokes the question “What constitutes success?”. Many times you will hear “The cement job was a success – we bumped the plug and had no losses during the job” Is this success? What is success? The first step in any cementing program should be to articulate the objectives for the individual cementing operations. Typical objectives could be: •

Isolate the shoe and allow drilling ahead with a maximum mud weight of xx

•

Isolate the shoe and a hydrocarbon zone

•

Cement back into the previous casing to provide structural support

•

Allow earliest drillout of the shoe

•

Facilitate earliest kick-off

•

Enable unambiguous testing of two hydrocarbon zones

•

Bring TOC to within 500m of the previous casing shoe, but not inside it

•

Bring cement returns to surface, but not too much

•

Isolate a high pressure zone from a low pressure zone

•

Isolate a potable water zone

Sometimes many objectives will exist together and the objectives of the drilling team may not always be those of the field production team. For example, the drilling team may be happy with cement at TOL and a successful liner lap pressure test. The reservoir engineers may be relying on long term isolation of several zones across the liner. It is now more common to have a multidisciplinary team approach to well planning and a much greater awareness of what the well is trying to achieve – technically and commercially. However, it is good practice to spell out just what the objectives are and make sure that everyone is aware and agrees. Although this may seem obvious, very few cementing programs ever lay out the objectives. It is only if these objectives are stipulated that it is possible to judge performance. If you can’t judge performance, you can’t do much to improve it. Cementing Operations Design Process 5-3 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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What are the major risks to achieving the objectives? There are very many cases throughout the oil patch of events happening which, prior to their occurrence, were thought almost impossible. On further investigation it has been realised that these events had happened before and were known. Wells have been cemented up, or junked, for quite trivial reasons or failures. The impossible happens – the real questions are: • •

how frequently what avoidance measures or contingencies can be put in place?

Risk Management is becoming well understood in Well Planning and is often used at the Drilling Engineer level to identify and handle risk and its implications for well cost. The same sort of approach can be used to ensure that planning for cementing operations on a well is robust and fit for purpose. When a cementing service company submits a cementing program to an operator this methodology is rarely apparent. Nothing can go wrong. In practice, you realise there are risks throughout the cementing process – from lab design and testing, through downhole equipment, mixing the slurry on surface, pumping, displacing, bumping the plug. In some cases, in some wells, a particular type of failure may not be too serious. In other circumstances it can be catastrophic. A particularly good example of this is HPHT wells. These wells present extreme difficulties in slurry design and downhole equipment reliability. Slurry designs can be very sensitive to even minor changes in additives or procedures. Thickening Times can lurch from excessively long to too short just through some seemingly trivial change in some parameter. If these risks are identified, quantified and the most important ones addressed in detail, then the chances of a successful job are significantly increased. If not, then the chances of a ‘train wreck’ will remain high.

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The Risk Assessment Process The steps in a structured assessment will be as follows: •

Risk Identification

List all the risks -

have all the right people contributed ?

-

was the whole operation examined systematically ?

-

have human factors been properly considered ?

-

how will a new risk identified later on be managed ?

It can be useful to look at risks through two lenses: •

Risks to the well and failing to achieve the objectives – e.g. failure to achieve sufficient leak-off at the shoe

•

Risk to being able to execute the job as desired (or designed) – e.g. failure to mix slurry to correct weight

The second approach may constitute a second Risk Register developed by the service company to provide assurance to the operator that it has covered its own planning and contingencies. •

Risk Analysis

Establishes the level of each risk in terms of severity and likelihood. May include making recommendations based on expected outcome

•

-

what sources of information were used ?

-

are there better sources ?

Risk Reduction

Management of safeguards -

can any risk be eliminated by doing things differently ?

-

are all existing safeguards properly understood ?

-

do all high level risks have a wide variety of safeguards ?

These steps should be linked to an implementation plan and some type of performance monitoring and should be preceded by a statement of the objectives of each cementing job on the well. Cementing Operations Design Process 5-5 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Needless to say, this needs to be a multidisciplinary team approach involving the contractors (not just the cementing contractor) and the operator. It can be argued that different types of wells require will require this process to be implemented with more or less thoroughness, with more or less time and expertise devoted to it, but all well planning should follow these steps. You would not expect a hospital to undertake an operation without deciding exactly what was the aim, how it was to be achieved, what the risks were and how to reduce them to an acceptable level. Examples The following are examples of the use of this type of approach. Each drilling team is likely to do things differently – in some cases maybe not so formally documented as in these examples. However, the steps are necessary.

Figure 1: Cementing BoD – offshore, exploration well Rev. 01/2002


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Figure 2: Cementing BoD – onshore well Cementing Operations Design Process 5-7 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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An alternative method would be to require the contractor’s Cementing Program to follow a particular structure, eg, for each cementing operation, Well section data ............................................................................................ 3 2.2

Objectives............................................................................................. 3

2.3

Assumptions and boundaries ............................................................ 3

2.4

Identified Risks & Mitigations............................................................. 4

2.5

Cementation method ........................................................................... 4

2.6

Spacer design....................................................................................... 5

2.7

Cement slurry design .......................................................................... 5

2.8

Casing hardware & acccessories....................................................... 6

2.9

Environmental evaluation ................................................................... 6

This document could be considered the Basis of Design and the actual Cementing Program could be a correspondingly shorter document. Cementing Risk Register – Example

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Cementing Program Unless the items are adequately covered elsewhere, this document should include detailed, final recommendations following detailed discussion and analysis: • Detailed well schematic • Annotated Lithology column highlighting risk zones • Objectives • The cementing method – inner string, two plug, single stage, etc • Recommendations for casing hardware, shoes, float collars, etc • The slurry design and properties – although these will be subject to confirmatory testing immediately prior to the job(s) • Where applicable, casing or liner running and surge pressure issues • Mud conditioning and displacement mechanics -

Mud properties Centralisation program – selection, placement, stop collars, etc Spacer(s) Flow rates Hydraulics modelling – pore/frac window, surface pressures, U-tubing

• All relevant job calculations, pumping schedules, materials requirements, etc • Job monitoring/recording • Where applicable, abandonment/suspension program recommendations • Contingency proposals – KO Plugs, lost circulation, squeezes, etc

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Personnel Competency The competency of the engineering support provided by a cementing contractor is a vital element for success. Securing experienced, motivated cementing engineers is increasingly difficult. The format below can be used as a basis for evaluating engineering support proposed by cementing service company. For certain types of operation – deepwater, HPHT, ERD – certain additional experience may be sought and specified in the assessment form. What is indicated here is just a guide to a more structured approach.


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Figure 3: Example COMPETENCY ASSESSMENT: ONSHORE CEMENTING ENGINEERING SUPPORT Area

Technical

GENERAL / BP SPECIFIC REQUIREMENTS

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Competence / Skill required

Skill Minimum level required

Cementing Experience

More than 2 years in an onshore engineering post and present for a minimum 10 cement jobs or, > 5yr as an offshore engineer + 1 year as onshore engineer. Must have worked for more than one Operator.

Aware of properties and functions of drilling fluids

Completed 1 week basic fluids course.

Overview of Well Construction Process

Either minimum 5 years offshore, or 1 week drilling engineering course.

Equipment selection and application

Understands principles of operation and limitations of squeeze packers, surface and sub-sea launched plugs, stage collars, centralisers and float equipment. Capable of doing all engineering calculations related to pressure testing operations.

Slurry Design

Aware of all API and BP specified test procedures. Understands function and limitations of cement additives. Can determine design temperatures by API and computer simulation. Minimum of 2 weeks laboratory testing orientation.

Language

Fluent in English

Cement Placement

Able to run cement placement simulator and determine optimum spacer and flow characteristics using a computer simulator.

BP procedures requirements and practices

Ideally will have worked within BP operations. Must be totally familiar with the Contract Scope of Work.


Assessed

Forward Action

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PERSONAL SKILLS

Presentation Skills

Attended training course and capable of providing concise, informative presentations.

Coaching / Supervisory

Can supervise work of junior engineers and be held accountable for quality and delivery of their work.

Team Skills

Is fully participative and speaks from position of authority.

Report Writing

Can structure concise report and demonstrate good written communications skills

Computer Literacy

Must be proficient with Windows based operating systems and familiar with Word and Excel

Commercial Analysis

Able to accurately generate cost estimates and reconcile well costs.

Risk Assessment

Must understand the risk assessment processes and aware of procedures described in BP GHSER practices.

.

Guidelines for completion of the assessment. Aims of the process. To select the most able and competent people to fill these critical positions for BP - positions which impact capital spend and non productive costs. Highlight the skills and competencies that are seen as important to BP to deliver first class business results. These skills may be different to those that the CONTRACTOR values for his business objectives but should be seen as complementary. Outcome from the assessment. The assessment is not set up to be pass/fail. Cementing Operations Design Process 5-13 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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The aim is to highlight where the candidate is strong and where development is expected. It is possible that, when the process is complete, it may indicate that a candidate is not suitable. It may indicate that a candidate is able to do the job, but that training on, and off the job, will be required to enhance performance to the high levels required. The selection process for different operations will also take account of the specific technical requirements of the operation. Process. Pages 2, 3 and 4 should be completed within the context of the Scope of Work provided by BP for this service. The scope provides the outline job requirements from BP’s perspective. When completing the “assessed box”, the competence level should first be determined numerically where; 0 is has no experience in this area. 1 is basic only in the assessed area 2 is competent in the assessed area 3 is highly competent in the assessed area. Narrative should then be used to indicate the reasons for the indicated level. The “forward” action box should be used to indicate what development is suggested to develop and grow the candidate in post. As an example. The assessed competence for computer literacy may be 1. Forward action could be to go on an Excel training course followed by re-assessment in 3 months. Evaluation As well as good planning and competent people, continuous evaluation of performance is essential if improvements are to be made. There are various ways in which this may approached. One is the end of well review report and another (in BP) is the Global Well Services Initiative (GWSI) reporting. Below is the BP Minimum GWSI reporting format (as of Dec 2001). Rev. 01/2002


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The End of Well Review should be a structured analysis: • • • • • •

what was planned, what was done, what went well, what didn’t go well, what could be done better, what did it cost: broken down by job and by chemicals, cement, services, hardware, personnel, etc

Nothing less should be acceptable – unfortunately, it is frequently not done with any commitment.


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Figure 4: Summary Job element

Comments

Traditional Cementing Service Company approach

Mud type and properties

Mud type will influence the shape and variability of the hole. As the hole becomes less circular, less gauge and less uniform, cementing becomes more difficult.

No input.

Hole condition

When TD is reached there is a chance to ensure the hole is clean and that the mud is in good shape with low gels.

Left to the mud company who feel they have done their part in reaching TD.

Casing/liner running & centrallisation

Surge pressures need to be minimised. Areas of immobile or gelled mud need to be swept. Pipe needs to be centrallised to a reasonable degree consistent with the job objectives.

Usually seen as a Drilling Engineer responsibility. The cementing company will run software, but not be pro-actively engaged. They will not usually challenge, just accept.

Slurry design

First fix the objectives of the job and define the properties which are required. Lab testing and QA/QC are absolutely critical.

The back-room. Vital role in avoiding ‘trainwrecks’.

Spacer design

There are three functions – be compatible with the cement and the mud, keep the mud and cement apart, enhance the displacement mechanics.

Source of revenue.

Mixing and surface equipment hook-up

Optimising this and having contingencies in place can ovoid shut-downs and problems during the job.

Offshore, the bulk system – often a source of inefficiencies – is the rig contractor’s responsibility. Cementing company relies on the operator.

Pumping schedule

This is where true engineering input should be apparent. However, it is easy to put numbers into software programs and create a mountain of print-out.

Need to see evidence of optimisation of the whole cementing process rather than a hydraulics calculation.

Evaluation, learning & optimisation

Keeping a Basis of Design document alive through the development and keeping End of Well reviews up to date so that experience is not solely in the personnel.

This is usually dropped in favour of current operations.


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A more structured approach: • •

• • •

Define the cementing objectives Itemise the Risks Ensure offset well experience is reviewed Address both the well objectives and the execution of the cement job Develop a Risk Register with mitigation plans and actions Ensure competency of people Ensure full and detailed End of Well Review

The resulting documentation should include: • • • •

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Cementing Basis Of Design Cementing Risk Register Cementing Program End Of Well Review


Cement Manual

Appendix Additional Information Publications ISO/API Cementing Specifications: ISO 10426-1 - Cements and materials for well cementing - Part 1: Specification (API Spec 10 & 10A) ISO 10426-2 - Cements and materials for well cementing - Part 2: Recommended practice for testing of well cement (API Spec 10B) ISO 10426-3 - Cements and materials for well cementing - Part 3: Recommended practice for testing of deep water well cements ISO 10426-4 - Cements and materials for well cementing - Part 3: Recommended practice for atmospheric foam cement slurry preparation ISO 10427-1 - Casing centralisers - Part 1: Specifications for bow-string casing centralisers (API Spec 10D) ISO 10427-2 - Casing centralisers - Part 2: Recommended practice for centraliser placement and stop collar testing (API Spec 10D) ISO 18165 - Recommended performance testing of cementing float equipment

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

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Guidelines, Check Lists Cementing Equipment – Operations Check List •

Check all feed lines to the cementing unit (water, mud, spacer, cement)

•

Check that the cementing engineer has prepared the unit (fuel, oil, cooling system, water, air, pump packings, etc). Check adequate spares available

•

Circulate cement unit including RCM prior to job

•

Pressure test unit early

•

Check Martin Decker pressure recorder – is it wound up and working?

•

Check data logger for unit, mud loggers for displacement

•

Densitometer – calibrated, working?

•

Check rate indicator – stroke counter, flow meter

•

If using liquid additives in cold conditions make sure they are not too viscous or are heated if needed

•

Check the liquid additive system has been calibrated, is fully operational and is loaded with sufficient of the correct additives.

•

Where small quantities of additives are needed, ensure a suitably accurate and calibrated device is available to measure – beware the inaccurate bucket

•

If adding to displacement tanks, check that additive concentrations take account of the displacement tanks dead volume

•

Check that pressure relief devices have been tested/certified

•

Check telephone/tannoy system is acceptable for communication between cementer and rig floor with the unit running. Use radios, headphones

•

All relevant PPE safety gear available, glasses, gloves?

•

Check all crossovers, subs, etc, have been drifted to allow passage of all darts, balls, plugs

•

Check cement head (on arrival at the rig site)

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-

Visually inspect the plug release mechanism

-

Back-up O rings and spares available?

-

Check 2” WECO connection is fitted with pipe seals

-

Check WECO threads for damage

-

Check pressure ratings

-

Check all valves on manifold

-

Check manifold is correct for the head

-

Check O-ring in the cap – is there a spare? Appendix-2 “Proprietary - for the exclusive use of BP & ChevronTexaco”

Cement Manual

•

-

Check plug release indicator if applicable

-

Check any quick coupling is compatible with the casing threads

-

Check O-ring on the coupling

Check float equipment to ensure it is correct type for the casing string -

Check all threads on float equipment

-

Check all protective wrappings and any foreign matter is removed from float equipment prior to make-up

-

Check equipment is functional, i.e. ball, flapper or sleeve is in the correct position for the type of equipment.

-

Check any balls and make sure they are in a safe place

•

Check displacement plugs are the correct size. Clearly identify top & bottom plugs. Be absolutely sure.

•

Check any bypass baffles and shut-off baffles are compatible with casing and plug systems

•

Check casing handling tools are compatible with casing being run

•

Check centralisers and stop rings – size, type, number – against program

•

If using a stage collar, check threads, condition, seal area, ports closed, etc.

•

If using sub-sea release, thoroughly check items, threads, seals, plugs, etc

•

Is there sufficient cement, cement & spacer additives, water for the job, allowing for contingencies and problems?

•

Have samples been sent from the rig for lab testing – particularly for offshore wells?

•

Have job simulations been run and sent to the rig – check when U-tubing is expected?

•

Is the estimated job time plus safety factor consistent with the pumping time (thickening time) quoted by the lab?

•

Is the bottom hole depth & temperature consistent with the lab tests? Look at any new log data and check against lab test temperature (Bottom Hole Static Temperature).

Cement Sampling Check List Particularly offshore, rig-site samples of all materials used in mixing the cement slurry need to be sent to the lab as soon as possible following loading. •

Are samples truly representative of those to be used on the job? – Water, cement, additives. Know which silo contains what, label samples with silo details. Look at additive lot numbers – are they all from one lot? Take a note of the numbers. Appendix-3 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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•

-

Has sampling been done correctly?

-

Have samples been adequately packaged?

Cement is a variable product and different batches from the same manufacturer may give quite different pump times even with the same retarder. Also, cement chemically reacts with any moisture – even moisture in the atmosphere – and the properties (pump time) can change depending on storage conditions and length of storage. This makes it essential that any cement samples are fully representative of what will be pumped on the job. Three methods are detailed below. Methods 1 & 2 are preferred.

1. in-line sampling from the supply vessel •

Take several samples during transfer

•

Do not sample at the beginning and the end of transfer

•

If the sample is for a job which will not take place for several weeks, then the sampling may be deferred and one of the other methods used

2. transfer from silo to surge tank •

Purge all lines between silo and surge tank

•

Remove any cement from the surge tank and dump

•

Fluff the silo and transfer cement into surge tank

•

Open butterfly valve on the surge tank and take cement sample

•

Dump cement in surge tank if possible and purge line from silo

3. sampling from a silo •

Fluff cement in silo, then depressurize

•

Open lid and remove sample – beware of trapped pressure

•

Do not take sample from the top few inches of cement as this may contain excess fines and be unrepresentative

Note: •

Ensure samples are from silos to be used on the job

•

Avoid mixing different batches of cement

•

If different batches are present in the same silo, can samples be secured of the individual batches or can the cement be homogenized?

Sample Packaging: •

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Cement is a very reactive material and will chemically react with moisture in the air. This will change physical properties like thickening time and compressive strength development. The extent to which this happens can vary widely. Some cements are particularly sensitive, others not so. In any case, Appendix-4 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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•

•

small quantities, e.g. a cement sample, are particularly vulnerable to exposure and, if not adequately protected, exposure of just a few hours can make several hours difference to the thickening time – generally lengthening it…. the consequences of testing such a samples and designing the retarder concentration can be disastrous! The following guidelines should be adhered to strictly: Cement container: Large enough for 5 kg, 10 lbs minimum Air-tight, waterproof and strong enough to remain so during transit Clean, dry and preferably un-used Completely filled to exclude as much air as possible Lined with a clean, previously unused, polythene bag Labeled to show the cement silo number, date, location, cement type and blend, sample method. Note: it is better to label the body of the container, not the lid. Additive containers Clean plastic bottles, 0.5 litre, 1 pint, or larger Water tight lids, sealed with tape to prevent unscrewing in transit Labeled to show location, date, source (LAS, bags, etc), additive name, lot number, etc Note: roll drums, or circulate LAS, to ensure active components of liquid additives are in suspension Mix water container Clean plastic bottle 3-4 litre, 1 gal, or larger Water tight cap sealed with tape Labeled to show date, location, type (sea or drill water). Do not use soft drink bottles.


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Pre-job meeting: •

Discuss all HSE issues and any special hazards

•

Review job objectives and expectations

•

Calculate expected pressure against volume pumped during the job. Review expected final pressure.

•

Decide on returns monitoring and pit space requirements

•

Review expectation of U-tubing during the job

•

Review displacement volumes to all important stages of the job

•

Review bulk delivery and contingencies

•

Review communications and who is in charge of what and where they will be

•

Contingencies – blocked cement line, excessive pressure – set maximum pressures for the different stages of the job, plug doesn’t bump on volume, etc

•

Use of a T or Y piece to allow a rapid switch from cement unit to rig pumps

During the job: •

Ensure density is achieved before pumping down hole

•

Ensure pressure on surge tank is controlled

•

Ensure density is maintained throughout the job – do not allow to drop of towards the end of the job

•

Do not use a densitometer as the only density measurement. Check periodically with a mud balance, preferably a pressurized mud balance.

•

If necessary to open the cement head to drop a plug or ball, minimize any break in the pumping. Ensure someone is responsible.

•

Keep track of the estimated downhole position of the cement based on the volume pumped so that any sudden changes in pressure/rate can be interpreted and understood

Keys to Successful Foamed Cementing General Concepts 1.

1.Communication a.Foam design 1.

Base cement slurry

2.

Constant rate versus constant density considerations

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c. Between service company and operator - rig operations and engineering d. Between pump operator and nitrogen unit operator during pumping operations 2. 2.Maintaining constant rate and constant density of base (unfoamed) slurry 3. 3.Maintaining correct ratio of nitrogen to base slurry 4. 4.Planning contingencies for possible problems during job a. Back-up communications b. Loss of automation on automated units c. Poor cement supply (dry and slurry), density variation d. Loss of key equipment - cement pumper, liquid additive system, nitrogen unit e. Line failure/leaks/plugs 5. 5.Safety a. Location (placement) of energized fluid equipment b. Securing energized fluid lines c.Protecting steel deck members from cryogenic fluids -- in case of liquid nitrogen leak d. Restricting access to areas of pressurized equipment during job. 6. 6.Quality Control a. Isolation of cement and additives 1.

Pilot testing for slurry design

2.

Pre-job field blend testing with rig samples

b. Calibration of liquid additive system, flow meters, pressure gauges, densometers c. Equipment maintenance - cementing and nitrogen units, foam generator assembly, d 1 inch and 2 inch valves. e. Data collection during job 1.

Pump rates

2.

Pressures

3.

Nitrogen flow rates Appendix-7 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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4

Cross-checks of liquid additive usage (gauging tanks to check liquid additive system.)

5.

Cement density - unfoamed and foamed

6.

Cement returns from annulus

Checklist for Foam Cementing Operations 1.

Formulate base cement slurry for cementing operation with lab/district materials a. Thickening time b. Compressive strength - unfoamed and foamed slurries c. Rheological properties d. Transition time - unfoamed and foamed slurries e. Solids suspension f. Free water g. Foam stability (Foam half-height/liquid drainage rate)

2. Pilot test base cement slurries with materials to be loaded for cementing operation a. Isolate cement b. Isolate additives and record lot numbers c. Record ID numbers of tanks loaded out for liquid additives (TOTE tanks, etc) 3. Determine required nitrogen rate for base slurry to obtain desired downhole foam density a. Determine if constant gas injection rate method can be used - operationally simpler 1.

Calculate foam density at top and bottom of column for this method

2.

Calculate average foam density in column and check against fracturing/pore pressures

3.

Adjust nitrogen rate, if required, and re-check foam density against fracturing/pore pressure.

b If constant gas injection rate method cannot be used due to foamed column length and fracturing/pore pressure limitations, break job into stages of constant gas injection c. Use the minimum amount of stages possible. Rev. 01/2002


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4. Determine minimum and maximum gas rate for nitrogen pumping unit a. Determine the maximum LIQUID (base cement slurry) rate possible based upon nitrogen requirements for foam density and nitrogen pump unit rate limit. b. Determine the minimum LIQUID rate possible based upon nitrogen requirements for foam density and nitrogen pump unit minimum rate limit. c Notify all personnel of this cement rate limit and target cement pump rate for job at 80-90% of this rate (maximum) d.

Liquid pump rate may be the limiting factor, depending upon cementing unit capability,nitrogen unit capability, and nitrogen requirements. Please note if the rate limit on the cementing unit is the rate limiting equipment.

The objective is to operate the nitrogen pumper and cement pumper in the middle to upper end of their power curves. 5. Consult with rig - foreman and toolpusher on location of nitrogen pumper, nitrogen tanks, placement of nitrogen injection lines and foamed generator. a. Ideally, nitrogen unit operator and cement pump operator should be in visual range of each other b. Nitrogen equipment should be placed, if possible, out of main traffic areas on the rig/location c. Nitrogen lines should be run out of high traffic areas and where the line can be secured at regular intervals to fixed rig equipment (to prevent lines whipping around if they parted). d. Foam generator assembly should lay flat on ground, deck or rig floor. e. Work out contingency bleed-off of pressurized lines if a valve plugs or cannot be opened. (Have the service company bring extra 1 inch and 2 inch valves) f. Water and a water hose should be available near all nitrogen equipment and water should be run on deck to protect steel from cryogenic (-373 F) in case of nitrogen tank leak. g. Use plastic barrier tape to mark of ‘restricted’ or low traffic areas during the cement job. 6. Arrange for radios and headsets for primary communications during cementing operation. 7. Arrange for alternative methods of communication in case radios are not available or fail. Appendix-9 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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(blackboards and chalk, etc. like the car racing folks use) 8. Determine method for providing constant density, supply and pump rate of base cement slurry a Batch mixing if cement volume is small b. Averaging or holding tank for continuous mixing operations where the cement mixing unit DOES NOT have automatic density control. c. Averaging/holding tanks recommended for cementing units with mixing tub volumes less than about 8-10 bbls (even if they have automatic density control) d. Averaging/holding tank size of 25 bbl (minimum) or larger recommended. 9. Arrange for job monitoring/data acquisition equipment a. Check calibration of all sensors b. Check cables\connectors\output devices 10. Arrange for tank straps/gauges to monitor liquid additive usage during the job and verify correct metering by automated liquid additive system. a. Prepare table with cumulative cement volume (base, unfoamed cement slurry) and cumulative amounts of liquid additives that should be consumed during the job. b. Gauge or strap all liquid additive tanks at regular intervals during the job and compare usage with table values. 11. Prepare table of total nitrogen rate (SCF/min) versus base cement slurry pump rate. a. Basic requirement for non-automated nitrogen/cementing unit equipment b. Back-up in case automation units on equipment fail/don’t perform properly c. Increment unfoamed cement slurry rates on 0.1 bbl/min from 1 to 10 bbl/min rates (upper and lower limits for the table should be the minimum and maximum pump rate determined in ITEM 4 above and not necessarily 1 to 10 bbl/min) 12. Calibrate all equipment on location prior to the job. a. Flow meters b. Liquid additive pumps c. Densometers Rev. 01/2002


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d. Pressure gauges/transducers e. Data acquisition devices 13. For automated equipment, have an electronics technician trained for that equipment on location for the job. 14. Take samples of cement a. As loaded on the boat/truck b. At rig during job 15. Check load tickets a.Verify amounts b. Verify lot numbers for isolated additives c. Verify tank numbers for bulk liquid additives (TOTE tank serial numbers) 16. Inform rig personnel of dangers of pumping energized fluids and ask them to avoid the rig floor and nitrogen equipment areas during the job. Minimize traffic in these areas.


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Offshore Platform Cement Unit Specification Design Philosophy and Service The Cementing Unit and accessories shall be capable of performing: •

All primary and remedial cementing operations

•

Pressure Operations on the platform

•

Well killing

•

Emergency Mud Circulation or cuttings injection

•

Well intervention support and general pumping operations

Options for new and fully re-furbished equipment will be considered. Other options: •

with and without full Automatic Density Control

It will consist of: •

Diesel power units and associated day tank

•

Transmission

•

High pressure pumps

•

Relief valve

•

Mix water pump

•

Displacement tanks

•

Recirculating mixing system

•

High pressure manifold

•

Working platform and control panel

•

Mixing system

•

LAS/LAP

•

Surge Tank

•

Back up mixing system

•

System for measuring and recording of pressure/flow/density Offshore Platform Cement Unit Specification -13 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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HSE Considerations The equipment must: •

Be suitable for Zone 2 Gas Group IIA, temperature T3 hazardous areas.

•

Have automatic and remote shutdown

•

Have acoustic protection to prevent more than 85 Dba at Operators control Panel

•

Be able to mix cement without generating dust beyond that permitted under legislation

•

Designed to minimise risks of trips and falls

•

Designed to minimise the risk of oil and chemical spills during maintenance and operation.

•

For well kill operations and emergency mud circulation the system shall be capable of start up and operations without main platform power for XX hours.

QA/QC Considerations All materials used in the construction of the unit shall be traceable and manufacture will be according to ISO9001. All fabricated parts should be sheared or plasma cut. Requirements/Desing Criteria Pressure and pumping •

Maximum operating pressure = 10, 000 psi

•

Pumping capability defined by:

•

2 bpm at 10,000 psi

•

3.6 bpm at 4900 psi

•

18 bpm at 1000 psi

•

Design must be capable of pumping of acids and base fluid without use of displacement tanks.

Cement Mixing Performance Slurry mixing rates to be a minimum of: •

12 bpm @ 11 ppg

•

6 bpm @ 16 ppg

•

2 bpm @

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22 ppg Offshore Platform Cement Unit Specification -14 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Liquid Additive Storage/Proportioning System to be capable of adding 4 different chemicals and storing a minimum of 30 bbls split 15/5/5/5. The system must be able to add chemicals accurately to permit mixing at 5 bpm with additive concentrations up to 2 gps in a 16 ppg slurry. Contractors must indicate upper limit on additive viscosity. Tank heaters will be required. There should be no shared manifold from the LAP’s to the displacement tanks. Recirculating Mixer Recirculating mixer should have a total volume of 25 bbl and have agitators such that it can be used to batch mix small cement volumes without retaining circulation through the recirculating pump. Displacement Tanks Displacement tanks will be 2 x 10 bbl and be calibrated in 0.5 bbl increments. They will have there own agitators to ensure effective mixing of any chemicals dosed at the displacement tanks. The tanks should be strong enough to carry 22 ppg fluids and be constructed to materials suitable for OBM/brines/fresh water/cement spacers/cement chemicals. All sump volumes associated with the mixwater lines shall be measured and indicated on the unit. Pressure Flow and Density Measurements There should be a minimum of two calibrated independent pressure indicators. Additional calibrated 10” gauges to cover 0-1000 psi and 0-3000 psi should be provided. Density measurements should be via non radioactive desnsitometers and accurate to +/- 0.1 ppg. The accuracy of all flow measurement devices must be advised. Back Up mixing System A back up mixing system to allow independent jet mixing must be provided. This must enable 16 ppg slurries to be mixed at > 5 bpm. Offshore Platform Cement Unit Specification -15 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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Surge Tank A surge tank is required to provide steady flow to permit mixing at rated defined above. Contractor is required to advise size of surge tank recommended for this system. High Pressure Manifold The high pressure manifold shall be configured for dual feed facility of cement to the drill floor cement manifold. A third line should be “teed” off this manifold and routed to the wellhead area for production kill operations. Optional Equipment For ADC option equipment must control cement density within +/- 0.2 ppg. The data logger must record pressure density and flow. Additional Information Recommendations are required to permit bulk cement sampling which does not require transfer to the steady flow bin or sampling from the bulk tanks.

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Guidelines for Setting Cement Plugs in Horizontal and High Angle Wells Plug Setting Guidelines Plug Design 1. Set the plug in gauge hole. If not possible, use a caliper log to determine the volume. If this is not possible use some other method (eg carbide slug). Use excess cement and circulate excess out if in doubt. 2. Aim for a 250 m plug length, or 20 bbl slurry, whichever is greater volume of slurry.

Slurry Design 3. Use a heavyweight (17 lb/gal, or more) slurry to get good compressive strength development. Use a reliable value of static temperature (BHST) at true vertical depth (TVD), preferably from log data. 4. Estimate job time accurately, including pauses for switching tanks and plug dropping, then get a Thickening Time with a 1 to 1-1/2 hours' safety factor. Use API squeeze schedule values of circulating temperature, based on TVD, with a 1 hour initial simulation of batch mixing at 80° F (or surface mix water temperature). 5. Slurry should have minimal (zero) API Operating Free Water and no Settling

Mud Removal 6. Condition mud by circulating at least one hole volume before setting the plug. 7. Use a stinger 30 m or more longer than plug length centralized with solid centralizers. 8. Pump a spacer, weighted half way between mud and slurry density, to fill 300 to 500 ft of drill pipe/open hole annulus ahead of the slurry. 9. If possible, rotate the string while conditioning the hole and until cement is in place.

Cement Placement 10. Use some sort of bottom barrier for the plug to sit on - either a Viscous Reactive Pill ahead of the slurry or a ‘Para-Bow’ device or a weighted slug of heavy viscous mud Guidelines for Setting Cement Plugs in Horizontal and High Angle Wells -17 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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11. To avoid jetting the slurry straight down the hole use a diverter sub. 12. If hydraulic integrity is a priority, use a sacrificial stinger and a top barrier device. 13. Use a wiper plug to ensure accurate displacement unless incompatible with barrier devices in the string.

Job Execution 14. Use a batch mixer to prepare the slurry, checking the density with a pressurized mud balance. 15. Pump the spacer round the stinger in turbulent flow unless there is a risk of exceeding formation fracture pressure. 16. Pump the cement into the annulus at 2 to 2.5 bbl/min. 17. Pump a few barrels of spacer to balance the annular spacer volume behind the slurry (accuracy is not too important in a high-angle situation). Weight this spacer 1 to 2 lb/gal higher than the first spacer to induce cement to fall out of pipe, to pull a dry string. 18. Pull the stinger out of the slurry slowly - 5 minutes per stand, or more. 19. With stinger shoe above calculated plug top, circulate excess cement and spacer out of the hole. 20. Wait until cement has 3,000 to 5,000 psi compressive strength before tagging and dressing the plug. The following are critical aspects: •

Batch Mix a heavy slurry

•

Keep the Thickening Time to job time plus 60 minutes, not more

•

Use more, not less, volume of slurry

•

Use a support for the plug - viscous heavy mud if nothing else

•

Slow down when cement is exiting the pipe, especially if using open ended pipe (use blanked-off pipe with holes in the side if possible - ie a diverter sub)

•

Pull out slowly

•

Wait long enough before attempting to KO

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Setting a Kick-off or Abandonment Plug in Open Hole BP Alaskan Guidelines Drilling Manager Authority:

Custodian:

M. Scheuring, L. Wilger, F. Hernandez, E. Dompeling

Issuing Dept.:

Shared (SSD)

All SSD Operations Scope: February 18, 1999

Issue Date: Control Status:

Revision Date:

Services

Drilling

March, 1999

Department controlled document

CONTENTS

REFERENCES BPX World-wide Plug Setting BHST/BHCT RP

Objective Abandonment Plug Abandon existing open hole to comply with Government Regulations.

Kick-off Plug Competent base to allow for successful kick off to new target on first attempt.

Keys to Success There are many factors that contribute to a successful plug. The chances of

Setting a Kick-off or Abandonment Plug in Open Hole -19 “Proprietary - for the exclusive use of BP & ChevronTexaco”

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obtaining a successful plug are greatly improved by following these points: •

Having a clean hole prior to pumping cement

•

Slurry density of 17.0 ppg for kick-off plugs Slurry density of 15.8 ppg for abandonment plugs

•

•

Batch mix slurry Keep the thickening time to job time plus 1 hr, not more

•

Correct temperature selection

•

Use more, not less, volume of slurry Use a support base for the plug

•

• •

Slow down when cement is exiting the pipe, especially is using open ended drillpipe

•

Setting the plug in gauge hole if possible

•

Pull out slowly Wait long enough before attempting to kick-off

•

Minimum Requirements for Cement Program To facilitate in smooth field operations, all cementing programs should include the following: •

Objective

• •

Cement Blend Required Slurry Properties

•

Cement Interval

•

Bottom Hole Static Temperature Bottom Hole Circulating Temperature

• • •

Approximate Pumping Time Top of Cement (TOC)

•

Volume of Cement Hole Size

•

% Excess

• •

Spacer Type and Density Preflush Type

•

Batchmixing Requirements

•

If for any reason one or more of the requirements is not necessary or available, the deficiency should be noted in the cement program and any necessary explanation given. Rev. 01/2002


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General Pumping Procedure 1.

Verify that AOGCC has been contacted for approval to set an abandonment or kick-off plug..

2.

RiH with workstring, conditioning the mud and hole until optimal conditions are achieved. Flowrates during conditioning should mimic flowrates anticipated while pumping cement.

3.

A mechanical bottom, mud spacer, or viscous pill must be set if the plug is not set on a competent bottom.

4.

Rig up to pump cement plug.

5.

Pressure test surface lines.

6.

Pump balancing spacer according to engineering recommendation (1000’ of the annulus capacity)

7.

Mix and pump cement, displacing at the maximum rate (limited by ECD constraints) to improve gelled mud removal then reduce displacement rate to:

8.

2 bpm for last 20 bbl for hole size < 12 ¼”

9.

3 bpm for last 40 bbl for hole size > 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”

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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


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”

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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


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


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


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.


Rev. 01/2002

Cement Manual

Rev. 01/2002


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


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


BP &amp; Chevron - Cement Manual

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BP & Chevron - Cement Manual