BP & Chevron - Cement Manual

The ChevronTexaco and BP

Cement Manual

Cement Manual

Table of Contents

Section 1: Overview:

Special Considerations:

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

Major Factors Influencing Success:

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

Common Cementing Problems:

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

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

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Roles and Responsibilities:

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

Cement Job Evaluation:

Temperature Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73Acoustic Logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74Segmented Ultrasonic Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .79

Section 2: Equipment:

Surface and Subsurface Equipment:

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

Casing Centralization:

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


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Section 3: Cement:

Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

Cement Slurry Design:

Slurry Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35The properties which are generally considered to be important include: . . . . . . . . . . . . 35Cement Slurry Mixing Water Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Quality of the Mixing Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36Density . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36Fluidity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Controllable Setting Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Sufficient Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38No Permeability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38Long term durability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

The Use of Cement by the Oil Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42Cementing Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42Adjusting the Water Concentration to Change Slurry Density . . . . . . . . . . . . . . . . . . . . . 43Effects of Extreme Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52Other Special Conditions, Systems and Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54Deepwater Situations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Guidelines for Selecting Flow Migration Control Slurries . . . . . . . . . . . . . . . . . . . . . . . . 60Scale-Down Laboratory Test Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Cement Sampling, Blending and Quality Control:

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


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Section 4: Displacements:

Displacing Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1The Displacement Problem in a Nutshell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1

Fluid Incompatibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2Rheological Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Minimization of Channeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Erodibility Technology:

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

Service Company Cementing Software:

Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51

Schlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51CemCADE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51Computer-Aided Design and Evaluation for Cementing . . . . . . . . . . . . . . . . . . . . . . . . .51

Halliburton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56OptiCem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56A Primary Cement Job Simulation Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56

BJ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59CMFACTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59Primary Cement Design, Analysis and Real-time Monitoring Program . . . . . . . . . . . . . .59

Mud Preparation and Removal:

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


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Section 5: Cementing Operations Design Process:

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

Appendix

Additional Information:

Publications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Guidelines, Check Lists . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Cementing Equipment – Operations Check List . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Cement Sampling Check List . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Offshore Platform Cement Unit Specification:

Design Philosophy and Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13HSE Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Guidelines for Setting Cement Plugs in Horizontal and High Angle Wells:

Plug Setting Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Plug Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Slurry Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Mud Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Cement Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Job Execution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Setting a Kick-off or Abandonment Plug in Open Hole:

BP Alaskan Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19


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

Final HTHP Guidelines Key:

Index

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


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Section 1: Overview

Special ConsiderationsIntroduction

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 andspacer systems design, but also the execution of the job, placement equipmentand techniques.

Cementing High Pressure - High Temperature wells (HPHT)

Cementing under conditions of high temperature and/or high pressure is oftenrequired in deep wells and/or wells drilled into environments that present hightemperature gradients. Deep HPHT wells have been drilled in many areas, forexample South Texas, the North Sea and Middle East . Extreme cases ofelevated temperatures include geothermal wells in California and Italy. In otherareas, for instance the Caspian Sea, pore pressures are high requiring very highdrilling fluid and cement slurry densities, but the temperatures are in not extreme.

In any of these applications – high temperature or high density - the cementingoperation requires considerably more attention to detail. The conditions are suchthat even minor overlooked details can cause failure. The lower tolerancesassociated with HPHT wells are extreme. Under normal well situations the samedetails may not present serious problems. Furthermore, the consequences of job


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failure are normally more severe than for ‘normal’ wells. This is due to thetechnical difficulties of drilling and completing these wells and the often elevatedcosts of such operations.

The best, most experience personnel and resources must be brought to thesewells. ‘Train-wrecks’ in HPHT cementing operations are usually caused by simplethings overlooked or by a complete, total, lack of knowledge about some criticalaspects 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 thewell temperatures is normally considered one of the most critical. In HPHT wells,temperature is, without question, the key to success of the job. Laboratory designof 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 isobtained, the lab designs need to be refined using exactly the same cement andbatches of additives that will be used on the job.

Another aspect often associated with HPHT wells, is the narrow porepressure/fracture gradient window. Accurate knowledge of this is vital for correctjob design. Additionally, realistic simulations of surge and swab pressures toestimate casing, or liner, running speeds and break circulation are essential.

An HPHT cementing operation should include contingency planning for situationsthat require unexpected cement jobs. For example, sidetracks, losses or casingshoe squeezes. The slurry and spacer designs need to be tested well ahead oftime. It can easily take a week of laboratory testing to achieve a slurry designwhich can be mixed and pumped with confidence at high temperatures.

The best possible quality cement must be used, and the additives must beselected for the elevated temperatures of the job. Sensitivity testing totemperature is needed on the critical properties of the cement slurry such asthickening time, fluid loss, free fluid, rheology and compressive strengthdevelopment. This is to cover the uncertainty normally associated with wellcirculating 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 thedesign (for example, the need to be able to control gas or water invasion aftercementing). Since elevated temperatures accelerate chemical reactions andeffects considerably, compatibility studies between the drilling fluid, spacer systemand cement slurries must be carefully conducted ahead of time.


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Cementing in Deep Water

Cementing in deepwater presents unique problems to the drilling engineer. Rigcosts are so high, that that the timing of each operation essentially controls thecost of the well. The selection of techniques used to drill the well is driven by thehigh cost of time. Thus, reducing that time becomes extremely important.Likewise, reduction/elimination of failures is essential. For example, it costsaround US $300,000/day for a deepwater rig. If, for example, waiting on cementtime could be reduced for a given operation from say 12 hours to 8 hours, the costof 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 accumulaterapidly. If it becomes necessary to repair (squeeze) a casing shoe, the cost of thatrepair could easily approach or exceed one million dollars.

In deepwater, typically a 30 inch or 36 inch conductor casing is jetted to about 200ft below the mud line (BML). Next, a 20 inch or 26 inch surface string is cementedusing an inner string method, with the returns being to the ocean floor.

T

Figure 1: Typical Deepwater Shallow Casings ConfigurationCourtesy of BJ Services

Deepwater Surface Casings and Shallow Water Zones

Water Sands



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While drilling the surface holes of these wells in the Gulf of Mexico and other partsof the world, formations shallower than 2,000 ft below mud line can be weak andunconsolidated. In addition, shallow, highly pressurized, water containing zonesmay be encountered. The presence of these shallow, pressurized water zones isquite hard to predict even with the use of shallow seismic methods. Thesecomplex situations, if not handled correctly, can easily lead to the occurrence ofhigh water flows through the cemented annulus of the shallow surface casing.Shallow water zones with pore pressures of around 9.5 lb/gal equivalent mayrequire (depending on the depth where they are encountered), as much as 12 to14+ lb/gal mud density to control them.

Operators have experienced pore pressures as high as 12.6 lb/gal very close tothe mud line. Very severe water flows have been experienced. It has beenreported that flow rates as high as 30,000 barrels per day are possible in somedeepwater locations. In these extreme situations, the shallow water flow ratescan be so high , that they can generate washout craters large enough to seriouslyjeopardize the integrity of the well. There are documented cases in the industrywhere uncontrolled shallow flows have practically "swallowed" the entiremulti-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 presentother 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, specialtechniques and cement slurry designs are used.



Cement Manual

Figure 2: World Areas Experiencing Shallow Water Flows

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 maxi-mize the potential for inhibition of the flows after cementing.

To accomplish this, sacrificial muds are sometimes used to drill the zones (theseare muds which are lost to the seabed since the riser is not yet connected). Thedrilling fluids will have some fluid loss control and tailored rheological properties tominimize the formation of progressive gels and of thick, mushy mud films acrosspermeable weak zones. This is done to facility mud removal during the cementingoperation.

Shallow Water Flow Areas

Confirmed Flow Potential Flow No Reported Flow



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Spotting fluids are sometimes placed across the entire annulus, or across thelower critical zones, before pulling the drill pipe. These fluids are designed tomaintain hydraulic control across the water zones, and may include some settingproperties to assist in cementing annular areas that may not be fully covered withcement during the cementing operation. They will not set so well, or as hard, ascement nevertheless can provide a barrier to flow.

The cement slurries used are specially designed and tested to be able to controlthe shallow water zones. Most of the currently used cement systems are foamed.Foamed slurries can be mixed at different densities using the same base slurrydesign. This flexibility is needed to be able to rapidly and easily adjust the slurrydensity to the levels needed to control the water zones.

Foamed systems have great sweeping properties to facilitate displacement of themud and/or spot fluid from the large annuli. In addition, they posses the ability tocontrol water and gas flows by their capacity to maintain elevated pore pressuresin the cement column while it goes through the transition stage. The cementslurries are often preceded by foamed spacer systems to again aid in displacingthe well fluids.

Shallow gas may also be encountered while drilling the shallow sections ofdeepwater wells, but generally is not so problematic as that of the shallow waterzones. In general, the same cement slurry formulations and placementtechniques needed to control the shallow water flows, apply to the control ofshallow gas.

The cool temperatures and the necessarily low cement slurry densities seriouslycomplicate slurry design. Temperature affects all the properties of cement slurriesthat are critical for deepwater cementing: rheology, thickening time, transitiontime, free fluid, fluid loss and strength development.

Excessive thickening times are undesirable and the goal must be to eliminate orminimise WOC time.

Transition Time is the time from when the slurry stops behaving as a fluid (fulltransmission of hydrostatic head) to the point when it develops a significantmeasurable rigidity. During the transition time of un-foamed slurries, the pressureexerted by the column decreases due to the generation of progressive gels whichsupport part of the annular load exerted by the slurry.



Cement Manual

This pressure drop can allow influx of formation fluid or gas into the annulus.Short transition times are therefore necessary when cementing across shallowwater zones. Again, foamed cement slurries, due to the presence of the Nitrogenphase, 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, ornear-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 com-promise zone isolation.

One of the main problems encountered while drilling and cementing highlydeviated, extended reach and horizontal wells is the tendency of solids from allthe fluids in the wellbore to settle on the low side of the hole. The Figure belowshows 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 furthercomplicate the problem, experiments have shown that solids beds on the low sideof highly deviated and horizontal holes can quickly become immobile (dehydrated)across permeability, making their removal extremely difficult.



Cement Manual

Research has shown that transport of cuttings in drilling muds becomes moredifficult as hole angle increases. Hard solids beds have also been found on thelow side of the inside of the casing. These ‘inside-casing’ solids beds are notalways easily removed by the cementing plugs; in fact, cementing plugs damagehas been observed in certain cases.

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 drillingthe 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 beendeveloped that are capable of reducing drag and torque in these wells, while stillproviding good centralization for the pipe. The most recent developments includerollers to effectively "roll" the pipe to bottom.

D e v i a t e d / H o r i z o n t a l W e l l s

• S t a t i c /D y n a m i cS o l id s S e t t l in g

• D if f i c u l t t or e m o v e

• S t a t i c /D y n a m i cS o l id s S e t t l in g

• D if f i c u l t t or e m o v e

M u d S o l id sM u d S o l i d s



Cement Manual

Settling of solids from the cement slurry and spacer fluids is also a seriouspotential problem Therefore, the slurry and spacer used in these wells must benon-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 achallenge for these wells. To estimate the well bottom hole circulating temperature(BHCT), a bottomhole static temperature (BHST) and/or the temperature gradientin the particular area is used. For vertical holes, the BHCT can be calculatedusing API published formulas or temperature charts. While the API method is theaccepted standard for estimating BHCT, the correlations were developed beforedeviated drilling was common. Factors such as hole size, pipe size, surfacetemperature, water depth (for offshore locations), mud type, pump rates, etc., varyfrom well to well and can have an affect on the actual BHCT. Most of the wellsinvestigated to develop the API temperature correlations were vertical. Thus, forhighly deviated, extended reach and horizontal wells, the API correlations shouldnot be used.

Other methods to estimate the expected well temperatures are available. Inextreme 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 andthe other with a horizontal section, the BHCT of the horizontal well will be hotterdue to the high constant temperature along the horizontal section. On the otherhand, if we compare two wells with the same measured depth (MD), one verticaland one horizontal, the BHCT of the vertical well will be the hotter because it seeshigher temperatures at the bottom of the hole.

One of the best ways of obtaining the BHCT of highly inclined and horizontal wellsis using downhole temperature recorders specially designed for this purpose. Oneof the available designs consists of a memory recorder that can be tripped into thewell with pipe or can be dropped down the drillstring during a cleanup trip. Thetool measures the temperature at the bottom of the hole versus time. Onceretrieved, the tool is connected to a portable computer and a graph obtained. Thiscan be used to estimate BHCT but it should be born in mind that the geometry is



Cement Manual

different. In cementing the annulus is small and the pipe large. When the gauge isrun in DP, the pipe is small and the annulus large. This can result in different flowregimes and different heat transfer results.

However, with several of these BHCT measurements at different depths in a givenfield, a reliable BHCT correlation may be developed. Of course, on critical wellsthe cost of making these BHCT measurements may be acceptable; but it is oftencritical wells which have high costs and the time is not made available.

Next to actual measurements of the well temperatures, software temperaturesimulators can be used to predict BHCT at any well deviation and geometry.Simulators are capable of estimating the entire temperature profile up and downthe well, not just the BHCT. In long horizontal sections, due to the near constanttemperature, the circulating temperature tend to be near constant too.

The best way to use simulators is to first match measured temperatures from thewell (such as log temperatures). This allows fine-tuning of the simulation to obtaina more reliable prediction of the BHCT temperature at the depth of interest.

The Measure-While-Drilling (MWD) instrumentation can provide a temperaturewhile drilling. The BHCT temperature obtained from MWD at the depth of interestis typically higher than the actual BHCT is during cementing, but it provides anupper limit to estimate the BHCT for cementing.

Cementing Extended Reach Wells

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



Cement Manual

Courtesy of Weatherford

Figure 4: Extended Reach and Horizontal Well Sections

BeiruteBeirute C onsulting Consulting

Extended ReachExtended R each

A pplicationsA pplicationsExtendedReach sections Horizontal

well sections



Cement Manual

Extended reach wells, by definition, present long sections of hole where the angleof inclination is high and essentially constant. These extended sections of holecan be many thousand of feet. It is not uncommon to find extended reach wellswith measured depths of 15,000 feet or more. These extended sections furthercomplicate problems like formation of solid beds, the difficulty of centralizing thepipe, etc. All of the comments made in the previous section on cementing highlydeviated and horizontal wells apply to cementing extended reach wells.

An additional factor can be the very high ECD’s which result from the pressuredrop in the annulus in the long hole sections. This can impact displacement rateswhich, coupled with eccentric pipe, can lead to massive channeling of cementthrough the mud. This again emphasizes the need for a fully integrated approachto job design. The aims and requirements of the cement job need to be carefullyset out and all the factors which might influence success addressed thoroughly.The mud, the hole condition, the pore/fracture gradient window, dog leg severityand many other factors will play a crucial role.

Cementing of Multilateral Junctions

Multilateral wells are wells with branches from a main parent wellbore. Thebranches are often highly inclined, or horizontal, and multi-directional. Whencementing 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.



Cement Manual

Figure 5: Multilateral Wells

For placement of thecement, industry "bestpractices" such as mudconditioning, centralization,use of spacer fluids, are allapplicable and should beused. The selection of theappropriate cement systemfor a multilateral well can beaffected by several factorsspecific to these types ofwells.

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 cementsystem is applicable in all cases. Furthermore, in some cases, there is nocurrently available cement which will provide the required pressure isolation at thejunction. Thus, the selection of the cementing system needs to be done on acase-by-case basis.

TAML Multilateral Well Classification

The most commonly used classification of multilateral wells is the TAMLclassification. TAML (TechnologyAdvancement of Multilaterals) is a group of operators withmultilateral experience who developed a categorization system for multilateral

Many multilateral wells are drilled offshore

Parent well may be a producer inthe conventional way

Multilateral well my be a re-entry well



Cement Manual

wells based on the amount and type of support provided at the junction. Thiscategorization makes it easier for operators to recognize and compare thefunctionality and risk-to-reward evaluations of one multilateral completion designto another. Recognized TAML levels increase in complexity from Level 1 (simpleopen hole mainbore) through Level 6 as shown.

Figure 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 cementingis 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 arebarefoot (open hole) with or without slotted liners. Level II junctions are alsotypically placed in consolidated formations. Again, no cementing is involved in theconstruction of Level II multilateral wells in the lateral hole sections. However, thecement sheath of the parent wellbore need to be considered when choosing alocation for the window for the lateral section.

TAML Multilateral Classification

Level 1Constructiontime: 1 day

Level 2Constructiontime: 2 - 3 days




Level 6Constructiontime: 5 -10 days



Cement Manual

Many conventional cement systems are prone to crack and lose their ability toprovide an annular seal during the process of milling a window, drilling the lateral,and constructing the junction. For these applications, non-conventional cementsystems are available. For example, research has suggested that foamedcements with gas content between 18 to 38% by volume produce more ductilesystems which are more likely to retain integrity. In laboratory experiments,foamed cement systems have been shown to withstand significant deformationand cyclical loading, showing no damage to the integrity of the cement matrix andexperiencing minimal permanent deformation. Cement systems containing latex,and latex with fibers, have also been used. The primary benefit of the fibers in thecement 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 wellboreduring 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 lateralsare also cased, but not cemented. Level III junctions are again typically placed inconsolidated formations. They have a non-cemented junction with no hydraulicintegrity at the junction. The lateral liner is anchored to the mother-bore. LikeLevels I and II, no cementing is involved in the construction of Level III multilateralwells 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 andcemented. They include a cemented junction. The junction does not requirehydraulic integrity to be a Level IV junction, but some Level IV systems requirehydraulic sealing at the junction.

In this configuration, the cements used to cement the lateral section mustmaintain their integrity under conditions that cements used for conventional jobsare normally not subjected to. For this junction configuration, a window is milledand a lateral hole drilled. A casing string is cemented through the window to formthe junction. The cement is then exposed to additional stresses when the junctionis completed. For example, the completion process may involve milling off thecasing stub that is left inside the parent wellbore. The milling process leaves aflush joint at the junction with the cement being exposed to the inside of the casingat the junction with the main wellbore.



Cement Manual

Some of the physical and mechanical properties that the Level IV junction cementsystems 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 junctionsystem. The cement at the junction will be exposed to impacts during thecompletion of the well construction.

Methods used to improve the impact resistance of cements include incorporatinglatex in the cement formulation. Foam cements have also been found to improvea number of the mechanical properties of cement systems.

Conventional cement systems, while having high compressive strengths, are verybrittle and prone to crack when loaded by impacts and/or internal pressurecycling. For conventional applications, this cracking of the cement may beacceptable because the cement is not always required to provide hydraulicsealing from within the casing, nor is the cement exposed to direct impact fromdrill pipe, tools, etc. while tripping in and out of the hole. However, for somemultilateral configurations, the cement is relied on to help provide the hydraulicseal at the junction. Inspection of a model junction will soon indicate that this isunrealistic.

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 developedcomputer modeling capabilities (finite element analysis, etc.) to better predict thebehavior/integrity of cemented sealed junctions when the well is loaded withvarious stress conditions (pressurized junctions, draw-down, etc.) and whenexposed to impact loads.



Cement Manual

One recent, novel technique that needs to be considered for Level IV multilateralwells involves the treatment of the formation surrounding the formation before orduring the construction of the multilateral hole section with special, low viscosityresins. For the treatment to work, the formation needs to be permeable to be ableto accept the resin. By injecting the material into the formation, the permeabilitycan 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 bythe mechanical completion used and not by the cement. The parent hole is casedand cemented. The lateral is also cased and cemented. Level V junctions areplaced in consolidated and in unconsolidated formations. They have a cementedjunction, but the cement is not necessarily relied on for hydraulic integrity at thejunction. The junction has hydraulic integrity by way of some type of packerassembly. 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 hydraulicintegrity at the junction. The junction has hydraulic integrity. Level VI junctionshave 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 hydraulicintegrity at the junction.

Coiled Tubing Cementing

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



Cement Manual

Squeeze cementing through coiled tubing (CT) is a relatively new operation in thepetroleum industry. Interest in coiled tubing squeeze operations increasedsignificantly with the success and cost savings generated in the Prudho Bay field,Alaska, in the 1980’s. Techniques and cement properties developed or identifiedby BP, ARCO and others for Alaskan North Slope operations served as thefoundation for CT squeeze operations throughout the world.

Squeeze, or remedial, cementing is a common operation in the petroleum industrythroughout the world. Most squeeze operations are conducted with a drilling orworkover rig, through tubing or drill pipe with threaded connections. Cement isthe most common material used for squeezing and represents approximately 7 to10% of the total cost of the squeeze operation. The rest of the job cost is relatedto well preparation, tools, waiting on cement (WOC), drilling out of excess cementleft in the wellbore after the squeeze, etc. Squeeze operations using coiled tubingoffer significant benefits for slurry placement, control of the squeeze process, andreduced squeeze costs. However, candidate selection and preparation, cementslurry formulation, and job design require special considerations to realize the fullpotential offered by the technique. A serious complicating factor is the reducedannular clearances often encountered when performing coiled tubing operations.

Using CT can eliminate workover rig costs and significantly reduce wellpreparation and post-squeeze cleanup costs. Using CT in workover and squeezeoperations has been successful in remote areas where rigs are not readilyavailable 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. Specialtechniques and material properties have been developed which improve theprobability of success and realize the cost-saving potential of CT operations.

The process of squeezing with CT is similar in many ways to squeezing throughconventional threaded tubulars. Many of the general techniques for problemdiagnosis, well preparation, and job design and execution used in conventionalsqueeze cementing operations apply to CT operations. However, there are somedifferences, and these differences can significantly affect the success of theoperation. CT squeeze operations are essentially scaled-down squeezeoperations: smaller tubulars and annular clearances, and generally smallercement volumes. As with most reduced scale operations, attention to details isvery critical in every aspect of the job.



Cement Manual

Coiled tubing lends itself to plugging operations because it allows the operator toplace small volumes of slurry in the wellbore more quickly and inexpensively thanwith conventional plugging procedures. Well pressure control can be maintainedat the surface through a stripper and blowout preventer (BOP) so it is possible torun into a live wellbore, and the production tubing and wellheads do not need tobe removed before the job. The tubing can be reciprocated during holeconditioning.

Temperatures in the wellbore for CT operations can be significantly different fromtemperatures in conventional squeeze cementing operations. Downholetemperatures are affected by many variables including the type of fluid pumped orcirculated, fluid density and rheological properties, volume pumped or circulated,rate of pumping, and the well configuration. Generally, the temperatures in CToperations are higher than in conventional squeeze operations with threadedtubing or drill pipe, primarily because of the lower volumes of fluid pumped andthe lower flow rates used. However, with the larger CT workstrings, thetemperatures may be closer to the conventional case. For most squeezeoperations, and especially CT operations, accurate measurement of the wellboretemperature and temperature profile above and below the interval to be squeezedis necessary.

Most cement slurries for conventional applications are tested using well simulationtests developed by the American Petroleum Institute (API). These tests representa composite set of conditions, generally based on well depth, type of cementingoperation and geothermal gradient. It is important to understand that none of thecurrent API test schedules or procedures were developed from CT cementingoperations. Therefore, job-tailored test procedures and schedules should be usedto model the planned CT squeeze cementing operation as closely as possible tofield conditions. Job related information needed to formulate job tailored testschedules include the following:

Well temperatures (temperature is the most important variable affecting cementhydration.)

Well pressure (pressure has a lesser effect than temperature on cement hydrationbut has a significant effect on fluid loss. Well pressures can be reasonablyestimated from the hydrostatic pressure of wellbore fluids and the cementingfluids plus the expected surface pump pressure.)



Cement Manual

Mixing equipment and procedure (the amount of time the slurry will be held on thesurface before being pumped into the well can have a substantial effect on thethickening time of the cement, depending on the surface temperature, welltemperatures and cement slurry formulation.). Batch mixing of the slurry isrecommended, but the type of batch mixer and the way it is operated can affectthe 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 inthe mixing process and to the heating involved. Beware of over-shearing theslurry in a batch mixer with a centrifugal recirculating pump.

Expected pump-rate range (the time taken to pump the slurry down the CT to theinterval 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 cementslurry.)

Coiled tubing dimensions (the volume of the coiled tubing coupled with the pumprate can be used to design the thickening time test schedule for the slurry.)

Planned pumping schedule and technique. Modified well simulation testschedules 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 welloperation as closely as possible. It is necessary to duplicate the temperature,pressure, and pumping profile of the operations. For example, potential forhesitation 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 cementslurry (or other sealant) is not being sheared by pumping action. During theseperiods, the slurry may lose fluid and may develop gel strength, as the wellboretemperature begins to increase because there is no fluid movement to cool thewellbore. In most CT squeeze operations, some static or hesitation periods willoccur during the pumping operation. These periods can dramatically alter thethickening time of the cement slurry.



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The API Operating Fluid Loss test is a filtration procedure performed to determinethe 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 differentialpressure and at the expected well temperature for the squeeze operation. ForAPI tests, the filter medium is a 325-mesh, stainless steel screen. This screenhas 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 30minutes under the conditions listed above is the value of interest. However, forCT squeeze operations, the thickness or volume of filter-cake produced during thetest is also of interest. Pressure applied during a CT squeeze is often higher than1,000 psi, particularly when excess cement will be washed out to eliminate drilloutcost and time. In these cases, the filter-cake must withstand the pressuredifferentials present in the wellbore during cleanout of excess cement before thecement has hydrated and developed strength. The permeability of the filtermedium used in the API test is significantly higher than many formations,especially carbonates. In some test cells, core disks or synthetic (aluminumoxide) disks of varying permeability can be inserted in the cell by using anadapter. These adapters should be used when available, to better simulate wellconditions during the test.

For CT squeeze simulation tests, filtration time or the time of applied squeezepressure usually exceeds the 30 minutes used during an API test. Thus,filter-cake volume produced under downhole CT conditions can be significantlylarger than the filter-cake volume generated during an API test procedure at asingle pressure. The API fluid loss cell does not have enough volume toaccommodate all the filtrate generated from a CT in-situ test because of theextended time for squeezing and the higher pressures typically applied during CToperations. Cement slurries with filtrate volumes in excess of 60 ml will cause allthe slurry to form filter-cake (become dehydrated) in the API cell. Modifiedmethods for measuring fluid loss and filter-cake have been develop for CTapplications.



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Rheological properties of the cement slurry are more important in CT squeezesbecause of the smaller diameter workstrings and slim annular configurations,placement conditions, and squeeze techniques. Solids suspension, flowproperties, and gel strength development are of primary interest in designingcement slurries for CT squeeze operations.

“Strength of cement” usually refers to the amount of compressive load the cementwill withstand before failure. The compressive strength of a cement slurry can bedetermined by the API procedure in which an unconfined 2-in. cube (nominaldimensions) is compressively loaded (uniaxially) until the cement fails. Thisconvenient method of compressive strength testing is similar to failure testingprocedures used for construction industry practices from which the API methodswere developed.

The UCA (Ultrasonic Cement Analyzer) has the advantage of providing acontinuous measure of compressive strength vs. time. This compressive strengthis determined from correlations of sonic transit time vs. compressive strength, andtherefore, the results need to be calibrated with destructive API tests. The mode ofcement failure is tensile, or shear which is some 10% or so of the compressivestrength.

The API compressive strength test does not measure the strength of thefilter-cake for squeeze cementing. Cement filter-cake density can beapproximately 18 to 19 lbm/gal for a 15.8 lbm/gal slurry. It has been reported thatsome cement blends can build filter-cake compressive strengths of 5,000 psibefore the liquid cement slurry itself has developed any measurable strength.Under most conditions, the compressive strength of the filter-cake from a squeezecementing operation is two to five times greater than the compressive strength ofthe un-dehydrated cement.

Durability of the cement is a concern in many CT squeeze operations. Portlandcements are subject to attack by a variety of well fluids such as acid, certaincomponents in formation waters, carbon dioxide, and others. To increase cementresistance to acid and some brines, latex has been used in the formation. Fly ashhas been used to improve cement resistance to carbon dioxide.



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Regarding placement of the cement slurry, where possible, spotting cementacross the interval to be squeezed is preferred. The general procedurerecommended for spotting cement with coil tubing is listed below. This techniqueis 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 CTbefore pulling the CT string up.

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

5. For the last volume of cement, accelerate the CT pulling rate to allow the endof 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 tothe 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 tocreate the open hole must be removed from the annulus ahead of the cementslurry. Most investigators agree that the following factors affect the process ofmud 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 Rev. 01/2002

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Mud Condition and Mud Conditioning

Perhaps the most critical of the displacement factors is the condition of the holeand 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 themud is moving (circulating). Therefore, the goal of the conditioning process is toend-up with a “high mobility mud” across the entire annular length andcross-section. To achieve this, it is necessary, once the casing gets to bottom, tobreak and circulate all the pockets of gelled mud before the initiation of mixing andpumping of the cement slurry.

For deviated wells, the low end rheologies (and gels) of the drilling fluid arenormally higher than for vertical wells. The higher properties are needed tominimize solids settling from the mud on the low side of the hole while drilling thewell. 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 (seeFigur), 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 areduced rheology mud, etc.) before the cement job, that the cement job will gowell. However, as confirmed by large-scale experiments, if permeable zones aredrilled with mud with poor properties (capable of developing thick, gelled, partiallydehydrated, mud cake), it is extremely difficult to get the bulk of the mud in theannulus moving. In fact, there is evidence that pumping a high mobility


Rev. 01/2002 Major Factors Influencing Success 1-26

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(conditioned) mud in the hole during hole conditioning in this situation, may lead tochanneling of the high mobility mud through the low mobility (gelled) mud. At thesurface, the mud properties may look fine, giving a false indication that the hole isin good shape. In such a situation, the chances of getting a good cement job arereduced greatly. The answer is to ensure the zones of interest (pay) are nevercontacted by a low quality drilling fluid. The pay zones need to be drilled with ahigh mobility, good property drill-in mud that can be easily conditioned before thecement job.

Pipe Movement

A fairly straightforward and relatively simple technique to aid in the muddisplacement process is to move the pipe while conditioning mud and, if possible,while pumping the cement into the annulus. Full-scale displacement tests haveshown that simple pipe movement, either rotation or reciprocation, can improvedisplacement. Pipe movement helps remove gelled mud and assists in getting acompetent, 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 toside of the hole and this helps break much of the gelled mud. For highly deviatedand horizontal wells, the pipe may not move from side to side so well (arounddoglegs, for example).

With reciprocation in highly deviated/horizontal holes, the pipe may get stuck onthe upward stroke, potentially leaving uncased openhole. Reciprocationsometimes limits pipe movement to only pre-cement job conditions. In deviatedwells, rotation has an advantage over reciprocation in that it tends to drag thefluids all the way around the pipe (better mud removal).

With liners, reciprocation all the way to bumping of the plug has been used veryeffectively in near-vertical holes. Reciprocation is much better than no pipemovement, but regardless of deviation, with liners, rotation is preferred because itovercomes some disadvantages of reciprocation:



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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 reachesbottom 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 “mustdo” 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 ifthe pipe is close to, or against, the wellbore wall.

Adequate centralization of the casing is essential to obtaining good displacementof the drilling fluid and proper placement of the cement slurry around the pipe.Whilst pipe centralization is sometimes – incorrectly - viewed as optional forvertical wells, it is a requirement for cementing under deviated conditions. If thepipe is not mechanically centralized, the pipe will lay on the low side, making itimpossible to obtain a cement sheath that completely encircles the casing.Centralization of the casing helps provide a uniform flow path around the entirecircumference of the casing so that the mud can be more readily replaced.Large-scale tests have shown that mud displacement efficiency is directly relatedto the degree of casing centralization.

A standoff of 80 - 90% is recommended for cementing.

A well designed and executed casing centralization program will also greatlyassist in running the casing to bottom, and with moving of the pipe once onbottom. Special centralizers have been developed recently that reduce torqueand drag during running and moving of the pipe. The type and number ofcentralizers, and their location on the pipe, needs to be optimized using industryavailable computer programs, particularly for highly deviated wells.



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Fluid Velocity - Pump Rate/Flow Regime

The velocity (rate) at which the various fluids are pumped during the conditioningof the drilling fluid and during the actual cement job is a major factor in achieving agood 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 usuallydifficult to achieve turbulent flow without breaking down weak formations in openhole. 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 madeboth in full-scale displacement studies and in actual wells. The majority of theresults from the full-scale displacement studies have shown that the faster flowrates will provide better displacement efficiency. These results have beenconfirmed in actual field jobs where the percent open hole volume circulating wasmeasured as a function of flow rate.

It is now known that the higher flow rates provide better displacement efficienciesbecause higher flow rates generate higher shear forces in the open hole. Thehigher the shear forces (shear stress) on the hole, the more partiallydehydrated-gelled (PDG) drilling fluid will be broken free and circulated from theannulus.

Spacers and Flushes

Spacers and Flushes are used ahead of the cement slurry to prevent mudcontamination of the cement slurry (formation of thick masses), and to facilitatethe removal of the drilling fluid. However, spacers are very difficult systems tooptimize.

Spacers must be compatible with two fluids, the mud and the cement slurry. Ingeneral, these are very incompatible with each other. Spacers are designed to“work chemically” with muds and cement slurries. Since every mud and cementslurry is different, spacers should be essentially “custom designed” for every job.It should not be assumed that a spacer formulation which worked with a previousfield mud will also work with the present field mud, even if similar additives arebeing used. This is particularly important when designing spacers for oil-basedmud systems.



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When designing or evaluating a spacer system, the following criteria should beused 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 effec-tively 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 theparticular requirements for the given section of hole to be cemented. Of theutmost importance is keeping the design simple; including only essentialadditives. If ‘book’ formulations from previous jobs are considered, they need tobe very carefully re-examined to ensure they apply to the specific well conditionsat hand.

The cement, additives and field mixing water used in the laboratory to optimizethe slurry design must be the same as to be used on the job (same batches).

Cement quality is very important. A quality, consistent, API monogrammedcement should be used whenever possible. However, lower quality cements aresometimes used due to remote location and other factors including localgovernment requirements. In those cases, laboratory testing needs to be evenmore rigorous. For example, sensitivity tests of the slurry design to temperature



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should be performed, since the well temperatures that the slurry will see are notwell 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 bemeasured 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 willremain pumpable at bottom hole circulating temperature and pressure. The APIthickening time test schedules are “standard” based on generalized well designs(casing sizes, casing depths, pump rates, well pressures), and should be usedonly for preliminary designs, before details for the particular job are known. Oncethe details for the job are available: casing size, depth and mud density, as well asthe projected pump rate, these parameters need to be used to calculate ajob-tailored test schedule. With this approach, time to BHCT and maximum jobpressure often differ from standard API Schedules. This difference between the“job-tailored” and the API Schedules may have a marked effect on the measuredTTs for the slurries.



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Acceptable Values for Thickening Time:

A criteria for acceptable thickening time values is needed, to minimize WOC timesand 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 thebatch mixer) needs to be added to the calculated minimum TT, but must besimulated in the laboratory at the expected surface mixing temperature andatmospheric pressure.

Maximum TT acceptable is normally two to three hours above the Minimum TT.Longer maximum TTs may be acceptable provided compressive strength at thetop 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. Itshould be measured as closely as possible to downhole conditions. The preferredvalue for free fluid is zero, particularly for highly deviated wells, and particularly ifgas/brine migration after cementing is a risk. For nearly vertical holes, themaximum allowed free fluid should be around 1.0%, provided gas/brine migrationis not a concern.

Cement Slurry and Spacer Fluid Settling Behavior

A very critical property of the cement slurry is its solids suspending ability, bothduring and after placement, particularly for highly deviated and horizontal wells.In these wells, solids in suspension have a much shorter settling path than theywould in a vertical well. Because solids can settle out of a slurry while beingpumped the cement slurry must have sufficient yield point at downhole conditionsto prevent dynamic settling. After placement, the slurry must suspend the solidsuntil it develops sufficient gel strength to support them while setting.

The same comments regarding solids suspension apply to spacer fluids. Forexample, the spacer needs to suspend its solids statically to keep from grabbingdrillpipe during liner cementing.



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WOC Time

The waiting on cement (WOC) time is best determined using an UltrasonicCement Analyzer (UCA). The UCA provides a nondestructive way to continuouslymonitor compressive strength development under downhole temperature andpressure.

The test should also be conducted at the downhole T and P at the top of thecement column.

The cement slurry should be pre-conditioned in a consistometer. The preferredpractice is to run UCA compressive strength tests at both bottom hole and at thetop of the cement column or top-of-liner conditions to determine the optimum timeto resume operations in the well. Normally, operations should not be resumeduntil the cement has developed 500+ psi at the top of the column. It needs to beremembered that the UCA obtains the compressive strength from correlationsbased on the acoustic transit time of the cement. Often, it is found that thecompressive strength estimates of the UCA are conservative when compared withdestructive (crushed) compressive strength tests. However, the UCA estimate ofthe 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 withthe service company to make sure that job failures will not occur due toequipment. Similarly, service company personnel on location need to be welltrained and experienced in the particular operation at hand, and if possible, withthe particular field conditions. Many jobs have gone wrong due to surfaceequipment failures, and/or human errors, easily attributed to lack of experience ofthe service company personnel.

Since it is imperative for the cement slurry going downhole to have the sameproperties as the slurry designed in the laboratory, it is necessary for the slurry tobe mixed at the correct density. The old mixing device "the jet mixer" should nolonger be used to mix cement slurries. Modern mixing equipment withre-circulating, automatic density control and/or the high shear batch-mixersshould be used instead.



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Once the mixing operation begins, the only control the operator has over thecement slurry going downhole is the regulation of slurry density. The cementslurry is designed to have an specific solids-to-water ratio. Deviations from thisratio will affect the cement properties. Most slurries will entrain air during themixing operation. Chemicals are available that eliminate serious foaming but donot always prevent the formation under shear of minute air bubbles. When aslurry density measurement is made with a balance that weighs the slurry underatmospheric pressure, these tiny air bubbles can cause an erroneousmeasurement of the slurry density. The more accurate devices are those whichmeasure the slurry density under pressure (the pressurized mud balance).Pressurized density measurements during the job should be made to validate theaccuracy of the radioactive densiometer or other continuous densitymeasurement 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 throughlaboratory studies. Others have been obtained with the assistance of large scalelaboratory investigations, and successfully applied to the field.

It has been said that "one cannot apply what one does not know." In order to beable to apply the best practices to the cement job at hand, the engineer needs tohave access to these procedures. One of the main goals of this manual is toprovide the bulk of the accepted industry wealth of cementing knowledge to theengineer and field personnel. However, it will also be necessary for the interestedpersonnel to search the literature and to read many key papers written by industryexperts through the years, to help complete his/hers knowledge base. Some ofthe industry available best practices include the following, many of which will betreated 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



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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 thepore- pressure, fracture-pressure profiles for the well (see Figure). As the wellgets deeper, a good understanding of the window of operation becomes evenmore critical, since often the pore pressures and fracture pressures of theformations penetrated are closer together (narrower window). In deeper sections,it can become a real challenge to design the cementing operation such that thejob is performed without loosing returns (fracturing) or without the well flowingduring or after the cement job.

The challenge for the engineer is always to perform the cement job within thesafety window; making sure not to fracture the weaker formations, and notallowing the well to flow. It is also important to make sure that the hydrostatichead across the high pressure zones is higher than the pore pressures after thecement job is completed (static). This is important particularly when flushes (lowdensity spacer fluids) are used ahead of cement. Computer programs areavailable from service companies and operators that allow the safe optimization ofthe job. Factors that are taken into account to safely design and execute the jobinclude the well configuration, the volumes and density of all the fluids, therheological properties of the fluids, and the flow rates to be used during the job.



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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 cementingis critical. Temperature is the most important variable affecting cement hydration,and because of this, the need to accurately know the BHCT during primarycementing operations is normally well recognized. One of the first designparameters with any cement slurry design is placement time, which is governedby the expected pumping rates and the estimated bottomhole circulatingtemperature. The effect that different BHCTs may have on a given cement slurrydesign is hard to predict since it varies with the type of additives, temperaturerange, 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 ormore will likely force modifications in the slurry formulations (different additiveloadings, different additives, etc.)



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Circulating temperatures during actual cementing operations are difficult tomeasure and predict because they are affected by many variables. Sincemeasurement of circulating temperatures while cementing is normally not done,the oil industry has used for many years, other means to estimate wellboretemperatures during cementing operations. Under Cementing Highly Deviatedand Horizontal Wells in this section of the manual we examined severalconsiderations regarding the estimation of well temperatures.

The most common way of estimating bottom hole circulating temperatures for awell is the American Petroleum Institute (API) correlations. To estimatebottomhole circulating temperatures, the American Petroleum Institute (API) hasused measurements of circulating temperatures near the lowest point ofcirculation 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 hasserved over four decades as the focal point for gathering temperature informationuseful for cementing operations. Many of the data points used by the API camefrom wells where the drilling fluid was circulated for a sufficiently long period oftime to allow the temperature in the wellbore to reach a near steady-statecondition. Standardized thickening time test schedules containing temperaturesfor primary and remedial cementing operations have been prepared from thesedata sets. The temperature data in API RP 10B have been used by the industryfor nearly two decades. However, be aware that temperatures for a given wellduring cementing, or during circulation with mud, with casing in the hole may vary(in some cases significantly) from the temperatures estimated by the APIcorrelations. This is because the correlations are really "averages" (withassociated errors) from all the available data. In addition, as indicated above, thecirculating temperatures developed by the API came from data collected with drillpipe in the hole.

As mentioned under Cementing Highly Deviated and Horizontal Wells, the bestway to estimate the BHCT for critical wells is to actually measure it during acleanup trip using downhole tools provide by the service companies. The Figurebelow shows one of the industry available temperature recorders. The tools havebeen used in many wells to better estimate cementing temperatures.Measurements from the tools can be used to fine-tune computer simulatorpredictions to be able to estimate the entire temperature profile seen by thecement slurry during the cementing operation.



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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. Atleast 43 of the 50 US states have regulations controlling the drilling andcementing of wells drilled for the production of oil or gas. These regulationsinclude aspects like depth of casing seats, strength of the cement (mainly forsurface casing), WOC time, volume of cement used, need to circulate cement tothe surface, plugging and squeezing requirements, etc.

For surface casings, the main emphasis of the regulations is the protection ofpotable waters. Many states also require that mineral deposits be protected fromcontamination with hydrocarbons. The Tables below lists regulatory bodies andsome of the requirements in the US.

Drilling offshore outside the US territorial waters is governed by the MineralManagement Service of the Department of the Interior (MMS). Since regulationsand regulatory bodies change, it is very important that the current guidelines beperiodically reviewed to make sure drilling operations and cementing practicesfollow the requirements established by each state and local bodies (cityordinances, etc.)

More and more countries are developing regulations and guidelines for thecementing of wells. The Table list several countries that have drilling andcementing regulations. One part of the world that is working very hard to protectthe environment is the North Sea, particularly the Norwegian sector. This area isbasically a zero discharge zone, meaning that no materials can be dumped to thesea from drilling platforms. All drilling materials (cuttings, residues from tankwashing, excess cement and cement additives, tank washing, etc.) are required tobe transported onshore and disposed off using environmentally safe andapproved methods. The use of only government approved or green labelchemicals 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 andproperly discharged in many onshore locations.

In those cases were local regulations are non-existing, the operator uses bestknown practices and guidelines from other locations like the US to make sure thatfresh waters are properly protected, and that hydrocarbon zones are effectivelyisolated during cementing and plugging operations.



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Regarding permanent plugging of zones and abandonment of wells, regulationsnormally require the isolation, with cement plugs, of all potable waters, mineralsand hydrocarbon zones. Cement plugs are set either across the zones, or atsome length above and below the zones to create isolation in the wellbore. Thelength of the cement plugs normally includes 50 feet above and below the intervalto be covered. Cement plugs are also required to cover all casing shoes, allperforated intervals and any other questionable portion of the well that maypresent potential for communication. Additionally, a cement plug of about 25 ft isrequired right at the surface of the well. The previous section on Cement Plugsdiscusses the topic of abandonment in a little more detail, and the Figure belowillustrates 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 theactual execution is an essential key to success. It can be said categorically thatthe 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.



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Communication and co-operation must be established very early among allinvolved. All personnel must apply the best known cementing practices from thestart of planning. The team effort is also needed to handle all the quality controlmeasures 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 cementingcontingencies (kick-off plugs, squeeze of casing shoes, etc.), must start with theplanning of the well itself. Since cementing is the most important operationperformed to provide a competent conduit of the hydrocarbons to the surface,facilitation of the success of the cementing operations needs to be an integral partof the planning. For example, selection of mud systems that can provide neargauge holes must also be evaluated. Another aspect that can negatively affectthe potential for zone isolation is narrow annular clearances that makecentralization and cementing difficult, if not impossible.

All service company personnel must be consulted and made aware of the jobrequirements at the very early stages of the well planning process. They need tobe allowed to provide input based on their expertise, and they need to be allowedtime to initiate recommendations and testing of preliminary slurry and spacer/flushsystems.

Service company personnel that needs to be involved early include drilling fluidand cementing specialists and casing jewelry providers. They need to be talkingto each other and with the company drilling engineers and geologists. Questionsthat need to be asked should included the logistics of the entire process. Forexample, can we centralize this casing with these hole angles, and with this mudin the hole? What problems can be expected, and what things can we adjust, orchange, 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 inthe 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 alsotoward determining the information that may currently be questionable. Forexample, the source of the estimated well temperatures must be examined tomake sure that the data are reliable and that they can be used for the well athand. Plans may need to be made to obtain the extra data. Responsibilities needto be assigned to specific personnel to gather information. Preliminary computerjob simulations need to be initiated. These simulations need to be continuouslyupdated 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 potentiallyaffect the success of the cement job. For example, drilling fluid formulation and/ordensity adjustments are normally needed during drilling. Higher pressures thanexpected may be encountered, loses of mud may be experienced, sections of thehole may tend to slough, logging runs give better information regarding actual welltemperatures, lithology, pore and fracture pressures, etc. This information needsto be periodically passed to the cementing specialists, since this data may causechanges in the design of the cementing fluids and spacer composition. Also, theactual execution of the job may be impacted by the drilling data such as pumpingrates, pipe movement and centralization, volumes of fluids, etc. Fluid designs andjob computer simulations need to be revised/updated as the information from thedrilling is obtained.



Cement Manual

We said above that the planning process is a team effort. It is also adynamic/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. Forthis, a more detailed look at the requirements of the operation is based on all theinformation collected during drilling. Well temperatures are fine-tuned and fixed.Slurry and spacer densities are finalised. Laboratory tests are performed and thefinal formulations for the tail and lead slurry are decided on. Final testing is donewith the cement, additives and field water to be used on the job. Spacer design isfine-tuned and final compatibility studies are done using a drilling fluid samplefrom the well. Final bulk equipment (transports, pumps, batch mixers,densiometers, data recorder, etc.) are cleaned, check for performance andreadied 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 tomake sure the equipment will be ready and properly installed. If centralizers andscratchers will be installed on the rack, arrangements are made for the installationto begin as soon as the casing has been inspected and cleaned. Final decision ismade as to when the cement and other materials will be brought to locationSpotting of the equipment, and any other location related decisions (like locationof 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 personnelinvolved to make sure that the operation goes smoothly, preventing breakingdown of weak formations, and avoiding getting the casing stuck. Procedures forcasing movement during cementing are revised. Liner setting procedures andcontingencies are reviewed. A decision is made as to when the spacer andcement slurry mixing operations will start.

Meetings are held going over the entire cementing operation, reviewing personnelassignments, 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 spacerdensities, etc.



Cement Manual

During casing running, running speeds need to be controlled and checked vs. thecomputer simulations for surge and swab pressures. Responsibilities areassigned to specific personnel to make sure the casing is run according to thepre-calculated speeds, paying special attention once the casing starts below thelast casing shoe, and in particular as the casing approaches the bottom of thehole. Line testing pressures are decided upon based on the expected jobpressures and the weakest pressure rating of the equipment (normally thecementing 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 wellloses complete circulation once the casing is on bottom? What if the liner cannotbe set? What if we do not see the pressure blip when the dart picks up the linerwiper plug? How much over-displacement (if any) will be pumped if the plug doesnot bump, etc.

During and After the Cement Job

Once the job is in progress, hopefully all possible situations have been reviewedand contingency plans are in place for any unexpected event. The job needs tobe performed exactly as planned (rates, volumes, etc.). and all the data collectedso 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 isreviewed with all personnel involved, and discussions are conducted as to howthe job went vs. the expected pressures, etc.



Cement Manual

Common Cementing ProblemsIntroduction

Understand some of the common problems associated with primary cementingoperations 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 jobor during the life of the well. The severity and cost of these problem varies withwell type and location.

Failing to Bump the Top Plug

To minimize contamination of the cement slurry with the fluids ahead of it whilebeing 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, abottom plug is used in front of the spacer, and another in between the spacer andthe cement slurry. The first bottom plug pushes and wipes the drilling fluid fromthe casing walls as it moves down the pipe. The second bottom plug separatesthe fluids minimizing contamination, and also further wipes the casing. When thebottom plug lands on the float collar, a differential pressure is generated and thediaphragm or disk on top of the plug ruptures to allow the fluids to continue inttothe annulus.

Following the cement slurry, a top plug is used. This plug is solid, and alsominimizes contamination of the cement slurry, but the main function is to causeand signal the termination of the cementing job by generating a pressure increasewhen it lands on top of the bottom plugs. Based on the casing size and depth ofthe float collar, a displacement volume to "bump the plug" is calculated. A fewbarrels before the calculated displacement volume is reached, the pump rate isslowed to make sure that the plug is not landed with excessive force causingdamage to the casing or surging weak zones in the annulus (hydraulic hammereffect).


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On occasions, the plug does not bump at the calculated and pumpeddisplacement 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 displacementvolume is pumped). This is clearly an indication of a serious human error or of amechanical problem as outlined above. For example, displacement volumeshave 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 notabsolutely necessary for the plug to land, often the pumps are shut down afterpumping the calculated displacement volume and the cement slurry allowed to set(WOC time). Another approach is to pump an extra one half the shoe-trackvolume (casing volume between he float collar and the float shoe) to see if theplug bumps. If not, again the pumps are shut down and the job terminated. Thislast practice is more common with the large casing strings. With the smaller sizesof casing, this approach needs to be used with extreme caution because of thereduced capacity of the casings, and the great danger of over-displacing(pumping displacement fluid around the shoe), causing what is called a "wetshoe" situation. A wet shoe will require a cement squeeze operation of the casingshoe.

The end result of the top plug not bumping may be that more cement needs to bedrilled inside the casing before drilling ahead. This is not near as serious ascausing a wet shoe by over-displacing, so normally, under-displacement ispreferred.


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There are situations, however, where it is necessary for the top plug to bump, forexample if an external casing packer needs to be inflated, or if a hydraulic stagetool needs to be opened. In these cases the top plug not bumping can be a veryserious problem. For these cementing jobs, a pre-agreed procedure needs to beon hand outlining actions to be taken. Obviously, calculations and meteringdevices need to be checked and double checked to obtain the best possibleestimate and measurement of the displacement volume needed to bump the plug.

A good rig will keep records of calculated and actual pumped volumes to pumpplugs so that efficiencies can be confirmed and/or adjusted. Some callibration ofrig pumps can be done by pumping from one mud pit to another but this does nottake 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, thereare 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 thelogs must be complimented by a review of the job execution against the programand expected behaviour before deciding that poor isolation exists. Many timeswhen the results of the analysis are not clear, the decision is made to produce thewell to see if communication manifests itself in the life of the well, rather thanendangering production by pumping cement (squeeze) near the productivezones.

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



Cement Manual

Sometimes during the life of the well, poor isolation becomes evident by theobservation of communication between zones. It can be noticed by theproduction of water or gas from a nearby zone, or by noise logs detecting flow to adepleted zone, etc. In these cases, isolation can be regained by performingsome type of repair procedure. The most common way to recapture zonalisolation is by performing an squeeze cementing operations. Squeeze cementingpractices are discussed in detail in the Squeeze Cementing Manual.

Where cross flow exists in an open hole section prior to cementing – perhaps dueto an induced fracture and a loss and kick zone open simultaneously - every effortshould be made to cure this before running casing.

Annular Pressure

Sustained Annular Casing Pressure can be caused by several factors. Oneobvious one is poor displacement of the drilling mud in the hole during cementing,generating mud pockets and channels that eventually allow communication offluids to surface.

Another cause can be flow through a micro-annulus. Micro-annulus flow mayoccur after the cement sheath is damaged during drilling out of the liner top, orcasing shoe, or by high pressure testing the casing after the cement has taken aninitial set (this may include when conducting a Leak Off Test). Similar effects canoccur if the cement is displaced with heavy kill weight mud and then a light weightcompletion brine is used. It has been shown in the literature that testing thecasing with pressure differentials of 4,000 psi and above over the differential thatexisted in the well when the cement set up, will cause damage to normal cementformulations. Extreme temperature changes during production can also causedamage 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 majorproblem – high pressure, but small volume. In other wells it can be a seriousproblem requiring difficult and expensive intervention.



Cement Manual

Certain cement formulations (e.g. foamed systems) resist extreme pressuredifferentials and temperature changes better than others. If a conventionaldensity cement is being used, one possible way to minimize damage duringtesting and drilling is to make sure the cement has had plenty of time to developmost of its ultimate strength before resuming operations. To ensure that thecement has developed sufficient compressive strength, accurate temperaturedata must be available when conducting compressive strength tests in thelaboratory. When drilling highly deviated or horizontal wells, the determination ofwell temperatures can be much more difficult than for vertical wells. In addition,offshore, the temperatures will be affected by water depth, sea currents and otherfactors. Care must be taken to ensure that the cement has cured sufficientlybefore drilling out the liner top or casing shoe, or testing the casing. The cost ofthe additional WOC time will not be as significant as the cost of trying to repair andseal a cement sheath that has been damaged because of premature resumptionof operations on the rig.

Annular surface pressure is not an uncommon problem. The U.S. Department ofthe Interior, Minerals Management Service (MMS) has stated that, of the 14,000producing wells offshore; some 11,000 exhibit sustained annular casing pressure.It may be noticed days, weeks, months or even years after the primary cementjob. Fixing the problem is normally not an easy task since it is very hard, if notimpossible, to pump even water down the annulus. In cases where it is possibleto pump, several materials can be used to remedy the situation. For example,micro-fine cement and polymeric systems. The polymer formulations can bemixed at viscosities near that of water, but harden or greatly viscosify once inplace. It has also been reported in some cases, that loading (lubricating) themicro-channels with water (pumping slowly until the channels are filled) hasmitigated sustained surface gas pressure.

If it is impossible to pump down the annulus, it may be necessary to identify thesource of the gas, and perforate the well to cause a seal across and/or above andbelow the source. This repair method causes production shut-down, and isnormally deferred until abandonment.



Cement Manual

Low Leak-Off Test (LOT)

The Leak-Off Test is used to make sure that the casing shoe is capable ofpreventing communication behind the casing, and that it will withstand the highermud densities needed to drill ahead. Casing seats are selected such that thecasing shoe will be cemented across a competent formation. A good prognosis ofthe fracture gradient at the section TD is normally available and there may beoffset wells with recorded LOT data to act as a guide.

When the LOT is low (i.e. leak-off occurs below the expected equivalent muddensity), 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. Thisproblem is resolved by performing a squeeze job of the casing shoe. This type ofrepair, when conducted correctly, is normally quite successful – but timeconsuming. Ever effort should be made to assess the reason(s) for the low LOTbefore performing a squeeze.

It is also possible that the formations around the shoe (or exposed when drillingthe shoe) are not as competent as expected. This is a much more seriousproblem since squeeze cementing will not solve the problem.



Cement Manual

Top-of-Cement Lower than Required

Cement tops (TOC) can be roughly estimated after the cement job byback-calculating from the end-pressure of the job – low rate just before bumpingthe plug. More accurate estimation of the cement tops can be obtained fromcement bond logs (CBLs) and/or temperature logs run within 24 to 36 hours of thejob. If the top of cement is lower than needed, several things may have causedthis. The more obvious one is not enough cement slurry used during the job. Thismay have been caused by human error or by a greater than estimated holewashout. Lost circulation during the job or cement fallback after the job may alsocause cement tops lower than expected.

For the conductor or surface casing, low top of cement is normally solved by usingspaghetti string or small tubing to do a ‘top-up’ job. For deeper casing strings, acirculation squeeze job may be needed to circulate cement above the currentcement top. Depending on well conditions, cement may be circulated takingreturns from the annulus at the surface from a set of perforations just above thecement top, or two sets of perforations may be needed for the circulation squeezejob.

Soft Kick Off Plugs

Soft kick off plugs can prevent sidetracking of the well. Several factors cancontribute to this problem, but the key cause is contamination of the cement slurryduring placement or after the plug is placed (plug migration due to densitydifferences).

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 allowsidetracking. Often the cement is expected to develop higher strength that thesurrounding formations (of course, this is not always possible). Therefore, kick offcement slurries need to be resistant to contamination with the wellbore fluids.Because of this, densified cement slurries (low water concentrations and densitiesof 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 ofcompressive strength even when mixed with some mud systems. In all cases,contamination tests need to be conducted in the lab with the particular drilling fluidin the hole and the selected slurry formulation and adjustments made as needed.



Cement Manual

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

The need to use densified (low water ratio, heavy density cement slurries)complicates the placement of the kick-off plugs because heavier cement slurrytends to swap places with the lighter mud in the hole. Therefore, the best plugplacement practices need to be used to protect the cement slurry from levels ofcontamination that would prevent sidetracking. This will often involve spottingsome very viscous mud or using a mechanical device to give the plug somethingto ‘sit on’.

Kick-off cement plugs are normally allowed to harden for 12 to 24 hours. Whentesting the plug, drill pipe with a bit is run in the hole and the plug is tagged andweight is applied. The time required to drill or dress off the top of the plug is usedas one of the means to judge the quality of the plug. A good kick off plug may drillat 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 ahard 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 orwash to a point low enough to allow setting of another plug, and the plugplacement procedure repeated. Often the second plug will work because the firstone contributes to forming a base that minimizes migration of the second cementslurry.

Percent Mud Contaminati

on

Cement Slurry Density

15.6 lb/gal 17.4 lb/gal

0 2910 7010

10 2530 5005

30 1400 2910

60 340 2315



Cement Manual

Liner Tops that Fail Pressure Tests

Good cement jobs on liners often carry a higher risk of failure than a primarycasing 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 byexcessive equivalent circulating densities (ECD) across weak formations due totight annular clearances across the open hole and in the overlap, and possibly bybridging of solids and/or drilling fluid filtercake across tight liner lap areas. Majorflow restrictions are often found at the liner tops due to reductions in flow areaaround liner hangers and polished bore receptacles (PBR).

Liner tops are tested using positive, negative or positive and negative differentialpressures, depending on the well requirements. When the liner top fails apressure test, this is normally a serious problem because, similarly to the situationof annular surface pressure after the cement job, it is very hard to impossible topump into liner overlaps. A mechanical packer may be the best option.



Cement Manual

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 clear-ances.

• Lost Circulation during cementing due to excessive pressures ECDs, bridg-ing 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 inclina-tion.

• 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.



Cement Manual

Less Common Cementing Problems

Flow After Cementing

Gas/water migration after cementing has been recognized as a problem in the oilindustry for decades. Much work has been done to investigate the causes andpossible solutions to this problem. Reduced hydrostatic head, particularly in tightfracture-pressure/pore-pressure situations and in highly deviated/horizontal holes,can make formation fluid migration control critical. A concise summary of thepotential causes of migration is given below.

Types of Gas Migration

It is generally accepted that gas migration can occur through three basicmechanisms. Proper identification of the potential gas migration path in a givenwell is critical in devising a plan to prevent the problem from recurring in futurewells.

• 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 gasmigration, occurs because of the following: Cement is pumped in place and theslurry gels, and then sets. During the setting process, the cement may go througha small amount of plastic-state shrinkage and/or may take water from any thickmud filtercake left against the permeability, or from bypassed mud (a mudchannel), weakening and shrinking the filtercake. When this occurs, micro-cracksproviding a flow path for gas migration may form between the cement and themud filtercake or mud pockets. This problem appears in cases where the mudcake is relatively thick and/or when there is poor mud displacement. As gas flowsthrough these micro-cracks, it begins to dehydrate the moist mud filtercake ormud pocket. As this dehydration continues, the crack gets wider, which allowsmore gas, which causes the crack to widen, and so on.



Cement Manual

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 wetalked about the sustained surface annular pressure problem. This mechanismcan also cause inter-zonal communication down hole.

Formation Fluids Flow Through Unset Cement

Flow through unset cement has been studied extensively, and many publicationshave been written. This type of migration occurs when the overbalance pressureis lost in a cemented annulus before the cement sets (or develops enough gelstrength to prevent invasion). The loss of hydrostatic pressure in a cementedannulus before the cement actually sets has been well documented and isillustrated in the following figure.



Cement Manual

Figure 14: Loss of Overbalance Pressure in a Cemented Annulus

The loss of hydrostatic (overbalance) pressure is caused by the combined effectsof static gel strength (SGS) development and volume losses (primarily caused byfluid loss from the cement slurry to permeable zones). As the cement gels, it cansupport some of the hydrostatic (overbalance) load and it becomesself-supporting. When the overbalance pressure is reduced due to cementgellation to the point that the pressure in the cement column is nearly equal to theformation pore pressure, formation fluids can invade the unset cement annulus.The buoyant force on the gas bubbles in the annulus can cause the bubbles tocoalesce and to percolate up the cement column (gas migration). If sufficientvolume of gas percolates up the annulus, a permanent channel (or series ofchannels or micro-channels) can form and remain in the set cement. The cementcan then exhibit a high permeability.

Transition Time

Laboratory research has suggested that gas can percolate through unset cementuntil 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.

C em entFlu id

C em entG els

C em entH arden s

C em entS ets

Form ation G as P ressure

O verbalanceP ressure

T im e

Hyd

rost

atic

Pre

ssu

re



Cement Manual

Figure 15: Gas Flow in Cement vs. Static Gel Strength

Beyond 500 - 1,000+ lb/100 ft2 (or some other high value), gas migration throughthe 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 theTransition Time of the cement. A better definition of "Transition Time" is the timefrom the start of development of gel strength (the point when the cement stopstransmitting 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 gasmigration, and before cement slurries were developed that can help control theflow, serious problems were encountered. Cases of blow-outs and fires are welldocumented in the literature. Nowadays the situation is much less common.When migration after cementing occurs, it is generally because the cementingoperation was not well designed, or executed, or the potential for migration afterthe job was not correctly diagnosed. In all cases of gas or water migration aftercementing, repair normally consists of determining the location of the source ofthe gas or water, and perforating and squeezing to seal off the offending zone.

No Gas flow

Gas Flow

0

100

200

300

400

500

0 10 20 30 40 50 60 70 80 90

Time (min)

Sta

tic

Gel

Str

eng

th (

lb/1

00 f

t2 )



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Cement "Flash Setting"

The so-called "flash setting" of cement slurries during pumping implies a suddenand rapid setting. Normally, cement slurries do not flash set. A cement slurryflash set would be apparent from an unexpected, very fast and large increase inpumping pressure, leading to a premature termination of the cement job. Somecement slurry formulations known as "right-angle set" cements do set very quicklyand go from a pumpable liquid to an extremely gelled, or set, state is just a fewminutes. However, like any other cement slurry, these cement slurries arenormally in place before the slurry gets to the point to where it right angle sets. Anexception may be if the cement has be designed at a much lower temperaturethan experienced in the well or is pumped at a higher density than lab tested. Or, ifthe slurry was pumped (say) without the retarder.

There are, nonetheless, some situations that seem as if the slurry hasexperienced a flash set. They include cases of contamination of the Portlandcement slurry with materials that tend to cause severe chemical reactions with theslurry. For example, calcium aluminate cements have been used in some wellsfor reasons including very high temperature applications (e.g. steam floods). Onoccasions, Portland cement slurries have been used ahead or behind the calciumaluminate cements. It has happened that the two types of cement slurries havecome in contact in the wellbore. This mutual contamination of the slurries hascaused a flash set at the contaminated interface. Also, Portland-with-gypsumcement slurries, if incorrectly used at high temperatures, may also set veryquickly. Finally, slurries formulated without fluid loss control, pumped in tightannuli, across highly permeable zones may dehydrate suddenly, abruptly causingthe formation of a bridge of dehydrated cement solids across the permeablezones. This, at the surface, would again look as if the cement suffered a flash set.



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Cement Manual

Roles and ResponsibilitiesAim:

• Understand the roles and responsibilities of those who contribute to a suc-cessful job.

• Understand the need for a multi disciplinary approach to achieve the opti-mum job.

The Well design

Cementing is the one of the most important operations performed in wellconstruction. In exploration/appraisal it can be vital to achieving the objectiveswith the minimum NPT and cost. In a development, the wells may never produceto their full capacity without good zonal isolation.

Company personnel have a responsibility to coordinate the planning and ensurethat cementing considerations are addressed at all stages of the decision-makingprocess. Decisions made during the planning of the well can substantially impactthe 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 directlyinfluence 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 andunderstood by all involved in the planning and execution of the operation.For example, the cementing objectives for the surface casing to protectpotable water zones will be quite different from the objectives of an inter-mediate casing that runs across zones with no potential for production. It isthe obligation of the operator’s personnel to clearly and unambiguouslytransmit these objectives to the service company. It is the responsibility ofthe service company representative to make sure that the cementingobjectives 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 variousobjectives

• Identify and manage risks

• Control costs

• Monitor and document changes

Clearly defined cementing objectives facilitate the design of the operation andfacilitate the post-job evaluation. Success, or failure, of the job will therefore notbe based only on bumping the plug, or not having mechanical problems during thejob, but on meeting the previously established and agreed objectives. Below area 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 struc-tural support for the well.

• Isolate the potential loss circulation zone in the XYZ formation from +/- 225to 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 notless 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 pres-sure (differentials to be selected later).


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• Obtain good mud displacement efficiency and no channelling during thejob, confirmed by comparing job recording (pressures, returns, etc.) vs.expected (simulated) behavior, and the location of the top of cement on topof the liner.

• Experience no lost circulation while cementing, preventing damage to theproductive zones.

• Minimize fluid loss to permeability from the cement slurry, preventing dam-age 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 stringneed to be reviewed, refined and updated, based on all the information gainedduring the drilling of the particular hole section.

In addition, to defining objectives, major risks to achieving these should beidentified and mitigation plans developed. Management of risk and control ofcosts should be evident in the approaches adopted.



Cement Manual

Information Needed by the Service Company

The service company representative needs to have, in addition to the clearlydefined objectives for each casing string, all the relevant information about thewell 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 theservice company representative. Tight hole status is no excuse to withholdinformation, and secrecy agreements can be used to protect the information. Theservice company cannot address important cementing issues if he, or she, is notaware of the location of the pay zones, pore pressures, etc. The following is theminimum needed by the service company representative. For specific situations,this may be extended,

Well configuration: casing sizes, grades and weights, hole /bit sizes, casingdepths

• Well trajectory

• Drilling Rig details

• Mud types, densities, expected rheologies

• Required tops of cement (TOC’s)

• Expected well temperatures – static, undisturbed geothermal temperaturegradient

• 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, spacerdesign or job approaches (special equipment)



Cement Manual

The Cementing Program

The cementing program is normally a part of the well Drilling Program andcontains details of the likely cementing jobs and the planned TOC‘s. Thisdocument may not outline in detail how the objectives will be achieved.

A detailed cementing program will be prepared by the cementing servicecompany. This will include details of all slurry designs, spacers, pumpingschedules, materials quantities and costs. It should include recommendations forall aspects which will have an impact on acieving the objectives. It should, forinstance, include recommendations for centralization and displacement rates.

Generation of a complete and effective cementing program is a team effort withactive participation of operator and service provider personnel (drilling engineer,geologist, mud engineer, downhole equipment supplier, etc.). Again, as moreinformation is obtained as drilling progresses, the cementing program must to bereviewed, 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, casingweights, MD & TVDs.

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

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

• Fracture pressure, pore pressure data vs. depth.

• Offset well information (when available) detailing problems experiencedduring drilling and cementing. Presence of high pressure zones, lost circu-lation, 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 contingencycasing string.

• Methods to be used to test/evaluate each cement job.



Cement Manual

• 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 detailedinteraction 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 detailedinteraction with the service company representatives has taken place.

• Details of the cement slurries and spacer systems proposed: density, vol-umes, fluid loss requirements, WOC times, cement tops, etc. Often to startwith, these sections are left almost blank until the detailed interaction withthe service company representatives has taken place.

The interaction with the Other Service Providers

In addition to the cementing service company, drilling fluid, casing hardware, rigcontractor (offshore rigs bulk system & delivery) and logging personnel need to beincluded and consulted on items that require their expertise. For example, thecementing company representative needs to actively interact with the drilling fluidspecialist and the operator’s drilling engineer to make sure the selected mudsystem will be optimised to facilitate the cementing operations. Likewise,consultation with the providers of hardware is needed to make sure the bestequipment is being used for the given application. Their help is needed tosimulate centralization and running of the casing (torque and drag forces)particularly in deviated and extended reach wells. Logging specialists need to beaware of the type of cement systems to be used, to make sure that cementinglogs are run and interpreted correctly, etc. This is particularly true whenlightweight, high quality slurries are used.



Cement Manual

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 aredrilled is preparation for a LOT or a FIT. The tests are performed to determine ifthe casing shoe job and the exposed formation are competent enough to supportthe increased mud densities needed to drill ahead to higher pressure zones (plusa safety factor to provide for protection in case of a kick). The LOT and the FITtests are basically the same, but the LOT carries the pressure increase to thefracture point of the formation, while the FIT brings the pressure to a given pointneeded to drill ahead, without necessarily fracturing the formation.

Figure 16: Illustration taken from the Applied Drilling Engineering SPE textbook series. Vol. 2


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To conduct the tests, the mud in the casing is conditioned or displaced to newmud for the next section. The casing is closed at the surface (BOPs) and a goodquality, 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 totake fluid, noticed by a departure in the observed pressure trend. The surfacepressure and the volume of fluid pumped are recorded and plotted on Cartesianpaper as the test is performed. The Figure illustrates the process. Once thedesired pressure is obtained, or the well starts to take fluid, the pump is stoppedand the pressure observed and recorded for 10 to 20 minutes. If the casing wastested before drilling the shoe track, the line of pressure vs. volume pumpedshould be plotted on the same graph. In the figure, the dashed line was plottedbased on anticipated results from previous tests (expected behavior). This lineand the casing pressure test line can be of great help when conducting andinterpreting the LOT or FIT.

As illustrated in the figure, the pressure vs. volume tends to fall on a near straightline. Point D, near the start of the test, can be used to estimate the mud's gelstrength development (resistant to initiate movement of the fluid). Likewise, theslope of the early portion of the line can be estimated from the compressibility ofthe drilling fluid, or the early measured slope can be used to estimate thecompressibility of the mud.

For a good FIT, when the pump is stopped, the last pressure point should fall onthe straight line. For a LOT, a point is reached (point A on the graph) where thedata departs from the straight line behavior. At that point, the formation (or theweak cement job) starts taking fluid. The pressure at point A is known as the leakoff pressure. Pumping is continued at the same constant pump rate after reachingpoint 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 toincrease 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 13-3/8in. casing is set at 7000 ft, it should require about 8.4 bbls of mud after all thecompressibility and slack have been removed from the system, if a surfacepressure of 2000 psi is desired for a FIT. This test would require about 34 minutesif pumping at 1/4 bpm.


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

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

Temperature Survey

Cements, when they set, generate energy, or heat of hydration, due exothermicchemical reactions. The temperature increase thus caused can be used to locatetop of cement (TOC) by conducting a temperature survey before the heat isdissipated into the surrounding formation. To obtain the best determination of thecement top, the survey must be conducted around the time of maximumtemperature increase.

This maximum temperature increase is generated at around the time that thecement develops its final set. One rule of thumb is that the maximum heatgeneration takes place at a time approximately equal to the time needed for thecement to thicken under downhole conditions multiplied by a factor of 2. Forexample, if the thickening time of a slurry is 2-1/2 hours, then the temperaturesurvey should be run at about 5 hours after bumping the top plug. This rule ofthumb is not 100% since it needs to be remembered that for long cementcolumns, the top of the cement column normally sees lower temperatures than theBHCT. Thus, it is not unusual to have to re-run the temperature survey again ifthe initial run fails to detect the cement top. On the other hand, if one waits toolong, the temperature surge may dissipate and the cement top may not bedetected.

Casing, in bbl/1000 ft/ 1000 psi

13-3/8 0.60

10-¾ 0.40

9-5/8 0.32

7 0.16



Cement Manual

A better rule of thumb is to run the temperature survey at the time when it isexpected that cement top has developed an early compressive strength of about50 to 100 psi. This places the emphasis on the behavior of the cement at the topof the column. Laboratory data from the Ultrasonic Cement Analyzer (UCA) at theconditions 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 cementtop.

A big disadvantages is the time delay required.

Acoustic Logs

The evaluation of the quality of cement behind pipe after the cement has set isone of the most difficult operations on the well. The problem is caused by the factthat the current tools and interpretative methods are not accurate, and are subjectto a great deal of individual interpretation of the data generated. This had lead tomany myths, misconceptions and misuses of the instruments and methodsavailable in the industry. Here we will not discuss how to run or interpret a sonicor ultrasonic log. That belongs in the Cement Evaluation Course. Instead, we willreview the proper way to make use of the logs as a tool to help evaluate thecement job.

The above difficulties with the currently available technology has generateddifferent approaches to the evaluation of cement jobs. On one hand, some in theindustry use the data generated by sonic or ultrasonic logs exclusively to evaluatethe cement quality, without examining other important and relevant data. Othersdo not believe in the tools at all and do not run them. The best approach is, ofcourse, somewhere in between the two extremes.

The proper evaluation of the quality of a cement job should include sonic andultrasonic logs, in addition to the examination of all the other information availableto the engineer. The cement job evaluation approach described below includesthe analysis of the data from all the different sources. These sources include theopen hole log data, the actual cement job execution and performance, theformulation and properties of the cement used in the job, and the data from thesonic and ultrasonic logs. Each of these sets of information needs serious



Cement Manual

consideration to increase the chances of performing an accurate evaluation of thejob. 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 cementjob is,

• was a serious effort made to use best cementing practices during the plan-ning and execution?

If the answer is ‘no’, then there is a good chance that the job did not producedgood results, and this lack of attention to good practices may point, along withother pieces of the puzzle, toward a possible bad job. When investigating the useof best cementing practices, several issues need to be examined. For example:

Hole Conditioning and Displacement Procedures: The application of goodhole conditioning procedures and mud displacement practices is essential to thesuccess. The actual use of these techniques varies with well conditions. If goodprocedures were used, this should imply a likely good job.

Proper use of Spacers: The job record should show that quality spacer systemsand proper spacer volumes were used. Lab data should indicate goodcompatibility with the cement slurry, the spacer and the actual location mud. If anoil based mud was used to drill the hole, the spacer should have been tested forit’s ability to water-wet surfaces. If all of this was done, this should suggest thepotential for good cement job.

Use of Cementing Plugs: A bottom plug ahead of the cement slurry should havebeen used. Another bottom plug ahead of the spacer would indicate that a goodeffort to minimize contamination of the fluids in the casing was made. No use ofbottom plugs points to possible contamination of the fluids in the casing. Thebigger the casing ID, the greater the chances of contamination of the cementslurry while going down the pipe.



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Casing Centralization: The centralization program should have been designedwith 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 allthe centralizers were actually run, that would indicate the potential for a goodcement job. If the pipe was not centralized, a very poor cement job is the likelyresult.

Use of Erodibility Technology: To remove the partially dehydrated-gelled mudagainst the permeability, were the spacer and job rates designed and executedwith that purpose in mind? If the answer is ‘yes’, that points to the potential for agood job

Pipe Movement, Use of Wire loop Scratchers, etc.: If other best cementingpractices were also applied, for example, if the pipe was moved during mudconditioning and during the cement job, and even better, if wire loop scratcherswere used to removed the gelled mud against the permeability, that should havehelped obtaining a good job.

Post-Job Information

Cement top: If, after considering the actual cement slurry volumes pumped, andwith the help of an accurate caliper log, the cement top is found (with the soniclogs, using back calculation from the final job pressure and/or with temperaturelog) at about the expected depth, this again suggests a good cement job. On theother hand, if the cement top is significantly higher than it should be, it is probablethat channeling occurred, suggesting a bad job. If the cement top is lower thancalculated, this may confirm a loss circulation problem that would be verifiableusing the record from the job pressures data.

Evaluation of the Recorded Job Data

Current onsite data recording technology allows a complete record of thecementing operation to be obtained and displayed during the job. The recordincludes density of the fluids pumped, surface pressures and pumping flow rates.If the rate of returns is being measured, the record can also include thatinformation. After the job, all the recorded data needs to be evaluated in detail.



Cement Manual

Job pressure behavior: The analysis of the surface pressure signature can helpdetermine if the job went well without loss circulation, channeling or inflow. It canalso indicate if restrictions were present during the job. The correct analysis of thedata includes comparing the record to the predicted values and trends, the onsetand end of free-fall, etc.

Density record: This record should be used to check if all the fluids were pumpedat the designed densities. Cement slurry properties can be drastically altered ifthe mixed density is not within the design requirements. Normally, the cementslurry needs to be mixed at the desired density +/- 0.1 lb/gal.

Other problems experienced during the cement job: The recorded data andthe comments from personnel on the job, should be used to decide if otherproblems 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 tosticking, etc.

Data from logging tools

All these sets of data and information can only point to the possibility of a good, orbad, cement job. The information must be used with data from logging tools tocome to an informed decision about the quality of the job. On the other hand, thecement evaluation logs are the only tools run to try to actually "measure" thecondition of the cement behind pipe. Again, the reason for the necessity to look atall the data available is that the cement logging tools are not accurate, and aresubject to individual interpretation. Other limitations of the tools will be discussedbelow.



Cement Manual

Tools Available

Sonic bond tools: These tools have the capability of "measuring" the bond of thecement to the casing and the bond of the cement to the formations. The bondhowever is greatly affected by the well conditions and other factors that will bediscussed below. The bond to the casing is inferred using the measurement ofthe sonic energy transmitted down the casing. The bond to the formation isqualitative and is implied by the characteristics of the formation signals receivedby the tool (variable density log). All of the tools except the segmented toolsprovide data that is omni-directional. This means that the data is averaged fromall the signals received from around the entire circumference of the pipe. This is aserious limitation of these tools. The segmented tools however, providessegmented 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 thesame information. The amplitude tools provide energy transmission data whilethe attenuation tools provide data on the amount of dampening of the sonic signal.The segmented tools provide amplitude or attenuation at specific locations aroundthe casing.

Ultrasonic Tools: These tools measure the reflection of an ultrasonic signal as itpasses through the casing and is reflected by the casing cement interface.Because these tools only give information on the condition of the cement-pipeinterface, 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 theformation-cement interface, and the tools cannot "see" that section of the annulus.The tools, however, are segmented and can provide the quality of the cementbond at many locations around the casing. The tools are claimed to be lesssensitive to (but still affected by) the presence of a microannulus. The followingare the types of ultrasonic tools available:



Cement Manual

Segmented Ultrasonic Tools

Scanning Ultrasonic Tools

The segmented tools provide impedance data at eight locations around thecircumference of the pipe. The scanning tools provide data at small segments ofless than 1 mm. The data from around the casing is very useful when the well isdeviated, where there may be channels on the bottom or top of the annulus andwhere there is potential for gas migration.

Tool Selection

The tool needed for evaluation of a cement job must be chosen based on wellconditions and requirements of the evaluation. Most of the time, the tools shouldbe run in combination to provide the best data for the analysis of the job. The tablebelow outlines the application of the different tools available.

Figure 18: Applications of Cement Logging Tools

ConditionSonic

(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 Chan-nel

Not specific Large at the casing Large at the casing Small at the cas-ing

Deviated High side Channel

Not specific Large at the casing Large at the casing Small at the cas-ing

Deviated Chan-nel on casing

Not specific Only Large Chan-nels

Only Large Chan-nels

Small Channels

Channel on for-mation

Not Specific Not Specific No No



Cement Manual

Quality of the Log Data

It is important that the data provided by the logs is of high quality. Many factorscan 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 ultrasonicones are also to a lesser extent. If there is a substantial difference in the logsconducted with and without pressure, then it is very likely that a micro-annulus ispresent.

Microannuli are frequently present in wells. They can form for a variety ofreasons. They normally do not compromise the cement job, but make theevaluation of the job with sonic or ultrasonic tools more difficult. The presence ofa microannulus is normally not a serious problem since flow is not likely or, if ittakes place, is very small due to the large pressure drops required. Gas is morelikely to be a problem than oil or water.

There are other special considerations when evaluating a cement bond log. Forexample, soft formations can produce a low stress environment for the cementand allow it to lose tight contact with the casing creating a microannulus thataffects log evaluation.

Some Log Interpretation Comments

Continuous good bond: If the log indicates good bonding all along the cementedinterval and the formation signal is good (comparison with the open hole sonic logand the Gamma ray log is very important!), then the cement job is generallyconsidered good, particularly if the bulk of the other information availablesuggests a good cement job.



Cement Manual

Continuous poor bond: If the log indicates little or no bonding all along thecemented interval, then the job may, or may not, be a good one. The examinationof the additional data will help decide the actions to take: ignore the log, or do asqueeze job?

Combination of poor and good bond: As with the previous case, the other dataavailable will help with the interpretation. In addition, detailed examination of thelogs 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 theformation exists across the shale barriers (Gamma ray is used to determine thepresence of the shales), isolation may still exist, and a squeeze job may not beneeded.

Low side/high side differences in the logs: If the wellbore is deviated, channelson the low and high side of the hole may be present. If the cement slurry exhibitsfree fluid, a channel would form on the high side of the annulus. The channel mayexist along the entire cemented interval. If the low side solids in the hole were notremoved prior to or during the cement job, a solids channel will be present on thebottom of the annulus. The use of the segmented tools can be valuable fordetermining the presence of channels on the top or the bottom of the annulus. Ifchannels 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.



Cement Manual



Cement Manual

Section 2: Equipment

Surface and Subsurface EquipmentSurface Equipment

Aims:

An understanding of the equipment used in well cementing - both surface anddownhole

Cement Mixing

Cement mixing equipment has to be robust and fail-safe. It has to cope with awide range of slurry densities and slurry types. It has to be capable of mixingcontinuously at relatively high rates (minimum 4 to 5 bbl/minute, or greater than 1MT/minute) and at a constant density. It must be able to cope with variations inbulk cement supply.

These are very demanding requirements and in the early days required skilledand experienced operators. Even today mixing can, and does, create problems. Itis, unfortunately, not that uncommon for the slurry to go downhole at a somewhatdifferent density from that designed in the lab.

Early mixing consisted of a jet mixer, hopper, small slurry tub and a cutting tablefor sacks. The cementer operating the unit would vary the water going to the jetsin 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 homogenisationtook place. This type of mixing set-up is still the default, fail-safe, method on manysophisticated modern units.


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Cement Manual

Figure 1: Early Mixing Setup

Problems with delivery of a uniform, consistent slurry at constant density lead tothe development of recirculating mixers with a much larger holding tub and theability to get better control of density before pumping downhole. These mixers stilldeliver the mix water through jets but the cement is fed through a knife gate whichcan be controlled by the unit operator. The cement and water meet with highenergy and and the resulting slurry is ejected with some force into recirculatingtank. Here the slurry is further mixed by paddles and there is provision torecirculate 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 anddownhole. While pumping, further water and cement are constantly being mixedand fed to the recirculating tank which now acts as an averaging tank, smoothingout 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 mostland operations this bulk will have been pre-blended (dry-blended) with additivepowders 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) andadditives (usually liquid additives) added at the time of mixing.

Both systems will usually involve a ‘surge tank’ which is essentially a small silo orbulk tank. This is used to provide a steady, near constant feed to the mixer and itis usually situated directly over it.



Cement Manual

Figure 3: Surge Tanks

Figure 4: Halliburton Skid Unit



Cement Manual

Batch Mixing

Batch mixers come in many forms and sizes. All are basically tanks which will holdthe slurry before it is pumped downhole. Some hold only 50 bbl; others are 100bbl or more. They will usually be equipped with some form of agitation. This maybe paddles, centrifugal pumps or compressed air.

The main use is in liner and plug cementing; the advantage being that the slurrycan be brought up to weight with all the additives, homogenised and even testedbefore being pumped. There is thus no variation in density or properties and thereis 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 thanrelying on the cementer’s skill and experience with the knife gate and watervalves. These systems can work well and reliably but a fall back system is goodinsurance.

Computer systems are essential for foamed cement slurry mixing with nitrogen.



Cement Manual

Pumping

High pressure pumping units, like the mixer, have to be robust and capable ofhighly reliable performance. The industry has standardised on triplex (threeplunger) pumps. Most cementing units will use two banks of triplex pumps – 2 x 3cylinders. These are fed by centrifugal charge pumps through spring loadedvalves. The pumps are very ruggedly constructed, can easily be stripped andrepaired and are generally very reliable. They can pump highly abrasive slurriesacross a full range of densities and rheologies. The pluger stroke can vary from 5to 10 inches and the plunger diameter from 3 to 6 inches. By altering the sizes, thedelivery capability of the pumps can be varied to cope with different circumstancesbut using the same horsepower of the unit – higher pressures/lower flow rate orhigher 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 parameterswhen pumping downhole using 2” treating lines.



Cement Manual

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

Recording

The variables of interest are:

• Slurry density

• Flow rate

• Pressure

• Cumulative volume



Cement Manual

These variables are rquired throughout the job – mixing, pumping anddisplacement. Where displacement is done by the rig pumps, either extra sensorshave to be installed and hooked up to the cement unit recording device or the datahas 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 – forexample, the final pressure just before bumping the plug can give arough check on the height of cement in the annulus and confirm theestimated TOC.

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

• Aid planning and optimisation of subsequent jobs – transfer oflearning

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. ThePressurised 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 themixing process. There is little time for this to break out and a normal mud balancewill give a reading which is ‘lighter’ than the downhole (compressed) density. Apressurised 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 tocheck the reading being given by the densitometer.



Cement Manual

Figure 5: Pressurised balance (top) and normal mud balance

Jobs have gone seriously awry because the cementer worked from adensitometer which has drifted off calibration. In any case, calibration of thesedevices should be routinely checked.

Flow rate

If the cementing unit is being used for displacement, the flow rate will be takenfrom the downhole pump stroke counter, corrected for pump efficiency.

If rig pumps are being used for displacement, then a separate flow meter isneeded or the data has to be obtained from the mud loggers and tied-back to thejob timescale.

Flow rate is particularly useful when compared with pressure.

Pressure

Pressure can be recorded from a tranducer at the the downhole pump dischargeand is also usually measured by a Martin-Decker gauge which records on acircular chart. Since the Martin-Decker is an old-fashioned clockwork device itoften provides a record when the more sophisticated devices, or the recordingmedia, fail.



Cement Manual

Cumulative volume pumped

This can be calculated from pump rate and time and also from strokes and pumpefficiency.

If displacement is with the cementing unit, then the number of displacement tankscan be counted to give a good estiamte. In fact, where displacement volume isimportant – pumping plugs, spotting fluids, picking up plugs, seating darts, etc –the cement unit displacement tanks are the most accurate since they do not relyon assumptions about pump efficiencies. Displacement tanks do need to becalibrated 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 bequite level.



Cement Manual

High Pressure Lines

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

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

SizeMaximum Working Pres-

sure (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



Cement Manual

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 15,000psi. This is an integral, or Non-Pressure Thread Seal (NPTS). Threadedconnections are not permitted between a positive displacement high-pressurepump 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 precautionaryawareness 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 frequentlyrequire 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/lowvolume and low pressure/high volume.

Bulk tanks may be pressured to only 15-40 psi but the energy stored isconsiderable and should not be underestimated. Bulk tanks and lines should besubject 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 pressuretrapped?



Cement Manual

High pressure treating lines are often subject to considerable rough handling andcan often spend long periods between detailed visual inspection.

In any pressure testing exercise the treating lines should be chained down toprevent flying around in case of a test failure. Personnel should be excluded fromthe viscinity and warning signs erected.

Wherever there is a chance of overpressure being applied there shoud be apressure 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-blendedcement to the site for the job.

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



Cement Manual

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 workingpressure of 40 psi but this is higher than should be required. The bulk tanksshould have a Pressure Relief Valve installed. This should be set slightly higherthan the maximum working pressure – say 45 psi on a 40 psi WP tank. Periodicinspection and testing of these devices is required.

When cement is pneumatically transferred over many feet (>30 ft) it can separateinto slug flow. The surge tank situated close to the mixer smooths out the deliveryand also allows for the switching of tanks when one becomes empty withoutinterrupting mixing.

Bulk systems on off-shore rigs are the responsibility of the rig contractor. Manyrigs have been built and are still in service which have less than ideal bulksystems. 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, bulkdelivery problems can be a major source of trouble for the cementer. Every effortshould be made to identify causes of problems with the rig contractor and stepstaken to resolve any short-comings.



Cement Manual

Off-shore bulk sysytems should always be equipped with driers on thecompressed air supply. Moisture from ‘wet’ compressed air can adversely affectthe properties of cement and render lab testing on pre-shipment sampleserroneous. In any case, samples should always be taken from silos offshore andsent in to the lab for checking. It is not uncommon for cement to be within theAPI/ISO Specification when it is put on the boat and out of specification when ithas been on the rig for a few days. Needless to say, boat bulk systems are afurther source of problems with cement quality – not least due to contamination oftanks 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 andwhether they have a facility to monitor release of the plug(s).

Subsea release plugs obviously differ from surface plugs and liners require adifferent system.

Sweges allow connection of smaller diameter pipe or lines to casing threads. Theycross-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 areattached; usually the larger, surface casing sizes



Cement Manual

The above head is a single plug cement head and manifold. If used with both atop and bottom plug, the bottom plug is loaded before the head is made up to thecasing. The plug is released ahead of the cement and then, after pumping the restof the cement into the casing, the head is opened and the top plug loaded. At thistime the cement is most likely free-falling in the casing and there will be a rush ofair as the head is opened. Alternatively, the bottom plug released and the spacerpumped, The head is then opened and the top plug loaded before pumping thecement. 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 andcirculation can be more or less continuous. Both heads have similar releasemechanisms for the plugs – often a pin horizontally screwed into the body of thehead.

Two plug heads are sometimes too long for the standard bails on smaller rigs andthere are always fears of releasing both plugs before the cement with obviousconsequences.



Cement Manual

Liner Cement Heads are similar in principle but hold the darts which are pumpeddown the drill pipe running string. They are, therefore, much smaller diameter.

A sub-sea cement head consists of an assembly holding the plugs within thecasing at seabed. These plugs are launched by darts or balls released from ahead on the surface (similar to the liner head).



Cement Manual

Cement heads need frequent inspection for damage and for wall thickness. Theyalso require periodic pressure testing. Details of the last pressure test and generalinspection 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 functionsproperly.

• Check the bolts that hold the release pin or bail assembly to the head andmake 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 con-tainer with the pressure test chart.

Minimum Pressure Test Requirement for Cement Heads:

In addition to the above inspection requirements, all cement heads must bepressure tested every 90 days to their component rated working pressure.Fasten a copy of the test chart to the cement head. Cement heads and theirmanifolds must have the normal annual inspections.

Float Shoes and Collars

Float shoes and float collars are essentially non-return valves installed at the deepend of the casing string so that when cement is displaced into the annulus it doesnot flow back into the casing. If there was no such valve installed, the cementwould U-tube back into the casing until the columns of fluid inside and outsidewere balanced. In fact, if a float fails to work, then pressure has to be held on thecasing until the cement has ‘gone-off’ sufficiently to be self supporting. This islikely 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 cementingshoe and a float collar. The collar is installed one or two joints above the shoe andmay also be the landing collar for the cement plugs. If one float valve fails, theother may hold.



Cement Manual

Obviously, these valves have to be able to cope with the erosion caused by mudand cement during pumping. In deep, hot wells (which often have high densityabrasive muds) this can be a servere materials challenge. Some years ago theAPI 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 floatedinto the well. Obviously, with a check valve in place the casing does not fill up withmud as it is run and the weight carried by the derrick is reduced. This can assistsome 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 thecasing grade and mud weight – it will collapse. Casing is usually filled every 5 to10 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-filldevice is like a normal valve except that during running in the casing the valve isheld open. The casing then fills with mud as it is run in and pressure surgesassociated with movement of the pipe are reduced. When casing is close tobottom 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 acertain flow rate.

Stage Tools

Stage equipment, either a stage collar or port collar, is placed within the casingstring to provide a selectable intermediate passage to the annulus. Stageequipment is generally used to protect weak formations from excessivehydrostatic pressure, to cement two widely separated zones, and to reduce mudcontamination.

Stage collars are typically hydraulically opened and closed using free-fall dartsand pumpdown plugs to select and shift the appropriate internal sleeve.The lowersleeve covers the ports initially.



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Once the first stage is complete, the lower sleeve is pumped down to uncover theports 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 andapplying pressure to the larger closing plug.

Once closed, the stage collar cannot be reopened. The pressure required to openand 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 careshould be taken to release the correct plugs in the proper sequence. The internaldiameter 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 pumpdownplug.

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 toan inner string of drillpipe – see below. They are available with sliding or rotationalvalve mechanisms, and may be opened or closed as often as necessary. Thesliding valves are generally opened with an upward motion and closed with adownward motion, and require a minimum of 10,000 lb to stroke. Port collars maybe placed as often as necessary in the casing string and selected in anysequence. There are no plugs to use, nor drillout required. Some shifting toolsmay be fitted with cup type seals to form a conduit from the inner string to theports.



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Figure 11: Port Collar Operation



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Casing CentralizationCentralization

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 (mudremoval, zone isolation).

Field experiences, numerous large scale experiments and computer simulationshave all shown that even a slight de-centralization can be detrimental to thecement 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 andpartially dehydrated-gelled (PDG) mud films across the permeability. In somecases, if the pipe is not centralized, it is possible that as much as 1/4 of the pipesurface area can be in contact with the mud cake and PDG films. This can lead tostuck pipe. Centralized pipe may only contact the mud cake in highly localisedspots.

The following simple example illustrates how centralizers can assist in reducingthe 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 thatthe formation consists of 10% sand and 90% shale


Casing Centralization 2-25 Rev. 01/2002

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Case on non-centralized pipe:

Calculate the force needed to pull the liner if it gets stuck across the entire openhole.

Assume that the pipe is contacting the cake along a 2” strip, the entire length ofthe 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. Inthis case, the added drag due to the centralizers is due the running force of thecentralizers.

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 forceneeded in the differential sticking case!

Conclusion: centralizers can reduce the chances of sticking the pipe!


Rev. 01/2002 Casing Centralization 2-26

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Non Centralization Equals Poor Isolation

Below are examples of large scale experiments run with centralized andnon-centralized pipe. The arrows point to the mud channels in thenon-centralized case.



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

Less sophisticatedcomputation can estimatethe movement of fluids invariable eccentricity annuli(eccentricity varying up

and down the annuls). An example of a non-centralized, long annulus is given inthe attached graph. In the graph, the left side represents the wide section of the



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non-centralized annulus. The right side represents the narrow section of theannulus. Notice that much mud (a large mud channel) was left on the narrowside of the hole.

Figure 12: Pipe Movement

Large scale experiments and controlled field trials have shown that good qualitymud in the hole and proper hole conditioning prior to the cement job, are the keysto the success - assuming good centralization of the pipe. Full mobilization of themud (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 thebenefit 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 ofhigh quality cable loop scratchers. The photo below (from a large scaleexperiment) shows the dramatic difference between pipe movement with, andwithout, cable loop scratchers.

Positions of fluids in annular segments in wellbore at 180mins

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

1 2 3 4

wide side narrow side

dept

hs (

ft) Tail Slurry

Lead slurry

W.B. Spacer

O.B. Spacer

Mud



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The sections of hole showing little to no dehydrated mud ring around the cementacross 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 awayfrom the formation wall. Key factors are:

• The tools have to provide enough load-support to overcome the normalforces tending to lay the casing against the formation, particularly in devi-ated holes.

• Enough tools need to be used to provide casing “centralization” over theneeded intervals.

• It is normally assumed (however not always the case) that the formationcan provide enough support for the tools (minimum embedment)



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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 twocollars. By design, the bows are flexible enough to allow passage of thecentralizer through restrictions, but are also provide sufficient stand-off inenlarged hole areas. The springs come in various shapes and dimensions. Therelaxed 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 forceswith 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 finsare not designed to flex and therefore maintain a constant OD. The centralizerspossess very little flexibility. These devices only adjust to slight hole restrictionsor enlargements. Several types of rigid centralizers are available. Good examplesof these devices are Weatherford's SpiraGlider and the STT-I-SL Slim Linecentralizer,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. Thesecentralizers have solid bodies and solid blades with constant blade OD. Theyhave zero flexibility and therefore cannot adjust to any hole restriction orenlargement. Good examples of this type of centralizer are the Spir–O-Lizer andthe aluminum spiral centralizers manufactured by Ray Oil Tools, Weatherford andothers.

Figure 17: Spir–O-Lizer



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Figure 18: Aluminum Spirals



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Some Important Advantages/Disadvantages

Bow Spring

Rigid

Solid

Advantages Disadvantages

Can adjust to varying hole sizes (can poten-tially 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,


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.

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


Positive stand-off in gauge hole Fixed OD. No flexibility. Incapable of adjust-ing 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 restric-tions. If the centralizer gets stuck, the only

way to get it to go through is to break the cen-tralizer or for the stop rings to slip (forming a

centralizers “nest”)

The design presents the highest flow restric-tion of the three types. Consequently, care needs to be exercised when using them in

narrow annuli (slim holes, etc.).



Cement Manual

How Much Cement is Needed for Isolation?

A few feet of well bonded cement (to pipe and formation) may be all that is neededto isolation a zone. However, we normally want better protection than that for thelife of the well. We try to isolate above, across and below critical zones andproductive horizons. We also need to properly protect and support the pipe forthe life of the well (corrosion, formation movement, etc.). Thus, normally, we needto design and attempt to obtain good cement jobs across long intervals. Washoutsand 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 tooptimize 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 toTD. These applications require the use of computer simulators to calculate thenormal, drag and torque forces based on well trajectory, mud type and density,and the centralizer properties. This will allow optimization of the centralizationselection, placement and numbers.

Good centralization (high stand off ratios) calls for centralizers with high restoringforces (like the bow spring type). Low drag forces require centralizers with lowstarting and running forces (like the rigid and solid type).

Rigid and solid centralizers have lower running forces than bow springcentralizers, but their fixed OD renders them incapable of responding to hole sizevariations. In addition, the drift of the previous casing often limits the OD of thecentralizer that can be run. The size (OD) of the rigid, or solid, centralizer in agiven case can be too small to generate the desired degree of stand-off for goodcementation. This becomes even more severe in cases where the open hole hasbeen 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 ofthe casing, but that requires the use of a simulator. Standoff at the casing sagpoint is lower than the standoff at the centralizer.



Cement Manual

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 impossibleto obtain 100% standoff with rigid or solid centralizers since the maximum OD ofthis 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 previouscasing:

8.599 - 1/8 in = 8.474 in.

Recommended (available) solid or rigid centralizer OD (from manufacturer'stables) 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 thatcan be obtained with this type centralizer!. It of course assumes that the hole isequal to the bit size (normally not the case). If we now assume a more realisticsituation and visualize the hole being larger (the entire hole or sections of thehole) than the bit size, then we can see the real problem with fixed ODcentralizers:

Hole OD (in.) Stand-off

8.50 83

8.75 71

9.00 0.63

9.25 0.56

10 (washout) 0.42



Cement Manual

Even the best obtainable standoff of 83% (hole size = to bit size) may not be goodenough to get a decent cement job!. For critical situations we want to design for90 - 95 % standoff. Normally rigid and solid centralizes cannot give us thatlevel of standoff in real holes. We need to also remember that normally thecentralizers are purchased and often installed way before the size of the openhole is known (caliper).

On the other hand, bow spring centralizers for this example can have max. OD'sof over 13 in., with a compressed OD of as low as 8.231 in.(less than the previouscasing drift diameter). Bow spring centralizers can potentially provide the desiredhigh levels of standoff, as long as the normal forces are not excessive (seebelow). So, the main advantage of bow spring centralizers is that due to theirflexibility, they present the best chance of properly centralizing the pipe (theissue of the quality and durability of bow spring centralizers will be visited later onin this document.)

The Benefit of Swirl (Spiral Flow)

Swirl can be beneficial to the displacement process. It can move cement from thenarrow side to the wide side to at least increase the chance of intermittantisolation. However, the danger lies in thinking that spiral flow is a solution to theproblem and sacrificing standoff (by not using bow spring centralizers).

Experiments to measure the angle and length of the swirl of different swirlinducing devices have been conduced by the industry. The bulk of the studieshave been performed in pipe, with no permeability (for example, the JIP atSouthwest Research Institute in San Antonio, USA in 1991). These experimentsshowed a rapid initial decrease in swirl downstream of the aid, which decayed at aslower rate as the distance increased. The effects of higher swirl angles havealways been concentrated in the proximity of the devices. This behavior isobserved even at high rates (Reynolds Numbers). Therefore, it is very doubtfulthat the potential benefit of the use of swirl inducing devices can be experiencedat locations other than at or very close to the device; regardless of the type of fluidor the pump rates used.



Cement Manual

An example test is shown below. Notice the high angles concentrated very closeto the device. Experiments and mathematical simulations have also shown thateven minor hole enlargements and eccentricity significantly reduce the beneficial

effects produced by the swirl due to portions of the flow bypassing the device andnot 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 willalways end up covering the entire annulus. Unfortunately, this is not always thecase in real holes.

Very few experiments have been conducted under realistic downhole conditions,including the presence of permeability and hole inclination. Permeability has adramatic effect on the mobility of mud films and solids laden beds on thelow side of inclined holes. Due to partial dehydration and gelation, mud filmsacross permeability often exhibit levels or resistance orders of magnitude greater

than non-dehydrated mud portions (this depends also on the mud properties. Oilbase type muds for example, generate the most mobile mud films). To remove thepartially dehydrated-gelled mud films, spacer fluids have to be designed with

rheologies high enough to be able to apply the needed levels of stress.



Cement Manual

Thin fluids often cannot generate the necessary stress at the fluid-mud-filminterface. Mud films around the cement, across the permeable sand can be seenin 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 thepresence of unremoved dehydrated gelled mud across the permeability, and abed of solids on the low side of the hole. Turbulators were also tested inpermeable, non-enlarged, inclined holes (small clearance between the blades andthe hole), and as expected, they did a better job of helping remove the mud thanacross washouts.

In the very near proximity of the turbulators, less settled solids and partiallydehydrated-gelled mud films were observed than away from the device, but thedevice did not completely clean the annulus, even right where the tool waslocated. The photo below is not very clear but it illustrates the point. Notice thebed of solids on the low side of the hole, right at the centralizer.



Cement Manual

Figure 20: Turbulator across Permeability in an Inclined Hole

So, swirl by itself does not completely remove the dehydrated-gelled films of mudand solids beds in the hole. Why?

Mobility of partially dehydrated-gelled mud film has been measured in large scaleexperiments. As mentioned, the mobility of those films can be orders ofmagnitude lower than the non-dehydrated mud. The film is removed if the flowingfluid applies sufficient interfacial shear stress higher than the resistance of thefilm. That the fluid turns with swirl inducing devices does not mean that theneeded stress is applied. Much of the energy needed to remove the film is lostwith 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 donot provide enough standoff.

Bow spring centralizers have also being found to improved mud cleaning in thevery near proximity of the devices. Crook performed experiments in pipes in1985. He showed that bow spring centralizers improve displacement in inclinedholes, particularly near the centralizers (SPE 14198, Crook, 1985). Also,remember that bow spring centralizers can be purchased with fins to furtherinduce flow disturbances at the device.

Anything which disturbs flow is likely to help but over a short length.



Cement Manual

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 shortradius holes and/or across "soft" formations. Cuttings beds, of course, offer a realproblem if they are pushed ahead. Therefore, caution needs to be exercised whenusing high angle blade centralizers.

In an experimental well, a 7" casing with 45 degree blade angle turbulators wasrun 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 wasagain pulled out of the hole. One centralizer was never recovered; another wascracked. No packing-off was noticed across the centralizers. A reaming run wasmade, and the casing went down this time, with some difficulty.

In a field case, packing-off problems have been reported while circulating withhigh angle blades centralizers. Plowing was suspected in this case when the holebegan packing-off while washing down the liner. The problem was cleared bypicking up the string and circulating.



Cement Manual

Quality of Bow Spring Centralizers

Concerns regarding quality and durability of bow spring centralizers aredefinitively justified. Some manufactures have marketed and still do, devices thatshould never be run in the hole. They are junk! Unfortunately, these poor qualitydevices have caused many users to be very skeptical and doubtful of theperformance of bow spring centralizers in general. Another problem is that theentire topic of stop collars, for some unknown reason, has been neglected bymany operators, and therefore not enough pressure has been applied tomanufacturers to produce and collars the can be used to keep centralizers inplace.

It is not uncommon to find operators concerned about the type, size, etc, of thecentralizers to be used, but leaving the issue of stop collars completelyunaddresed. Frequently, centralizers are no longer installed by trained servicecompany personnel. Torque wrenches are not used in the installations, etc. Manycentralizers that fail downhole become damaged because the collars allow themto move and end up bunched up across hole restrictions.

Fortunately, there are available in the industry, high quality bow springcentralizers. That has been shown during industry testing, for example by Amocoin 1992 and recently by BP (2000). During the Amoco study, destructive, non-APItests 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. Inaddition, they were tested under compression and impact loading by dropping aload of 1,900 lbs from a distance of 9 inches up to 30 times onto the topcentralizer collar. Needless to say, many of the centralizers failed. However, twodesigns held up very well: the old Gemoco (now made by Weatherford) and theold 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 highquality bow centralizers will not perform due to large normal and/or running forces,such as highly-deviated/horizontal, high dogleg applications. This needs to bedetermined using a good simulator like Weatherford's CentraPro. Torque forcesand drag need to be calculated as well as the standoff. The figures below aresimulator generated. The first one shows a case where the pipe could clearly notbe 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 tobottom. The centralizer of choice to run in this case is obvious.



Cement Manual

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) canforce 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 rigidor solid selection is again obvious due to excessive normal forces that can begenerated across for example severe doglegs.



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Durability and Wear

Published and field data tell us that friction coefficients in drilling operations aredependent mainly on the drilling mud and its additives (lubricants), so, not much isreally gained by using centralizers made out of "soft" materials. Actually, muchcould be lost due to wear! The data below shows that the material of choiceneeds to be steel over aluminum and other materials such as aluminum-zincalloys. Steel resists wear much better than the other materials, providing a betterchange for the centralizer to get to bottom without much wear (preservation ofstandoff). The wear factors shown below were obtained in the laboratory usingthe pin-on-disk technique. The test conditions are given first.



Cement Manual

Wear in Microns

Stop Collars – the neglected issue

Considering the complex issue of casing centralization, stop collars and theirholding capacity are the most neglected aspects of the entire topic.

Stop collars are extremely important to the successful centralization. If the collarsare damaged or if they move, even the lowering of the casing in the hole can bejeopardized. Centralizers become junk in the hole!

When hole conditions allow, centralizers are sometimes placed over casingcollars. This eliminates the stop collar concerns. On the other hand, thistechnique is not a good one for casing reciprocation (it is not desirable to have thecentralizer move with the pipe), cannot be used in tight annuli, and it tends toconcentrate the normal forces on the casing connections.

Different hole configurations require different collar designs, but they all have toprovide substantial holding force. Since the forces that the collar will seedownhole cannot be reliably predicted, the answer to the question how muchforce do we need is: as much as we can get!

Experiments have been conducted comparing the holding forces of different collartypes. Large differences have been reported among the different designs. Belowis the result of tests conducted back in 1992.

Collars with screws and "dogs" gave the greatest holding force. Tests have alsobeen conducted adding "Baker Lok" type materials in between the collar and thepipe. Those tests have indicated that you can substantially increase the holdingforce of a given collar that way (by as much as 5). Stop collars also need tore-tested. The API Spec-10D provides a method to test the holding and slippageforces of stop collars. Depth of the gouge on the casing after the collar movesshould also be measured. The tests should be conducted using the same gradesof pipe to be used in the actual wells.

Disk MaterialSpecimens

Steel Aluminum-Zinc Aluminum

Steel 4.5 31 135

Sandstone 7.8 45.4 357



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Cement Manual

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 - par-ticularly 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 thatpozzolans with lime produced a competent cementitious material that could beused 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 ofnatural pozzolan and lime.

Modern Portland cements started with the calcination of limestones - heatingCaCO3 - to produce quicklime (CaO). Later it was found that impure limestones

containing clay produced mortars that worked better than the more purelimestones. These findings led to the burning of blends of limestone (calcareousmaterial) with silica and clay (argillaceous) materials. In 1796 James Parkerproduced a material he called ‘Roman’ Cement; one of the first cements that setand and remained water resistant. It was used in Brunel’s Thames Tunnel and inrailway bridges built by Robert Stevenson.


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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.


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The dry process consists of crushing the materials separately, storing each inbins, performing chemical analysis on each and then blending prior to beingground to a fine powder. The final blend is analyzed, adjusted as needed, and fedto a rotary kiln.

In the wet process, the limestone is crushed and stored. The clays and shales arecrushed and mixed in water flotation tanks to remove unwanted impurities andlarge chunks. The dry materials are then mixed into this dispersion to form aslurry. The slurry is analyzed for correct chemical content. Then the slurry is fedinto a wet grinding mill, analyzed again and fed into the rotary kiln.

The normal concentration of material in either system is approximately two partslimestone 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 reactionstake place. First the free water or moisture is driven out. Then the clays andshales are reduced to silica and alumina. Further heating drives off carbondioxide from the limestone reducing it to calcium oxide. These compounds are


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further heated to temperatures of 2,600 deg F, 1400 deg C. At these temperaturesthe new cement compounds are formed. As the liquid material approaches thelower end of the kiln, the various compounds fuse together forming chunks ofmaterial called clinker. Clinker varies in size from dust to about 2 inches indiameter. The clinker passes from the kiln into either a grate or rotary coolerwhere it is cooled in air.

After a period of storage, it is ground in a ball mill with gypsum to form the finalcement. Gypsum, in 1.5 to 3.0 percent by weight of cement, is used to control therate of setting and hardening of the cement. The materials are ground to a specificfineness, dependent on the type cement desired, and the end product is stored inbins for shipment. This is the final grey powder material commonly known asPortland cement.

Figure 2: Portland Cement Burning Temperature Ranges

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 setcement. Minor concentrations of gypsum, sodium and potassium sulfate(Na2SO4 and K2SO4), magnesia (Mg), free lime (CaO) and other admixtures arealso present in cement. Normally these minor components do not significantlyaffect the properties of the hydrated cement. However, they do influence the rateof hydration, resistance to sulfate attack and they also impact the properties of oilwell cement slurries.

100 Deg C: Evaporation of Free Water

500 Deg C: Dehydroxylation of Clay Minerals

900 Deg C:Crystallization of Products of Clay Min-eral 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


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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 ofacidic well fluids, it can contribute to cement deterioration. At elevatedtemperatures (above 230F), the lime can react with finely divided silica added tothe cement slurry to form stable calcium silicates, which contributes to the integrityof 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 to65% of the total composition. C3S is the main strength producing material. It

contributes to all the stages of strength development, but particularly during theearly 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 thecement. 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 cementadditives and promotes rapid hydration (early strength development) and it is thecomponent that controls the initial set and thickening time of the cement. The settime of C3A can be controlled by the addition of gypsum.

Phase Chemical Nomenclature Percentage

Tricalcium silicate (called alite) C3S 65%

Dicalcium silicate (called belite)

C2S 17%

Tetracalcium aluminoferrite C4AF 14%

Tricalcium aluminate C3A 2%


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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 havethree percent or less Tricalcium aluminate. On the other hand, high early strengthcements 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 thesubject of controversy. It is, without doubt, very complex.

One of the keys to understanding lies in Calorimetric studies made from firstmixing of cement with water. These show two distinct peaks in the rate of heatliberation. The first peak lasts only a few minutes and for an oil well cementcorresponds to the time the slurry is on surface. Many reactions are occuring; theimportant ones being the formation of a gel coating on the grains (CSH gel) and acalcium 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 lastfrom 30 minutes to several hours, when little or no heat is liberated. The cementslurry remains liquid and behaves as if hydration had stopped. This is known asthe 'induction period' and is one of the reasons for the success of Portland cementsince it allows concrete to be placed in position. It also, of course, allows oil wellcement 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-permeablemembrane which allows water molecules to diffuse into the grain but slows downcalcium and hydroxide ion migration into solution. Therefore, osmotic pressurecontinuously builds during the dormant period until a critical stage is reached andthe CSH gel layer ruptures. This heralds the onset of setting. The rupturing isaccompanied by growths of ‘spikes’ from the grains and the locking together ofthese spikes causes viscosity increase and then strength to develop.

Grains of API class G cement well into the hydration process.

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

C3S

C2S

C3A

C4AF

C-S-H gel

(Colloidal –VariableComposition)

Ca (OH)2

Portlandite(Crystalline)

Sulpho-ferri-Aluminatehydrates

Fast

Slow

Fast but retarded by Gypsum

Gypsum

Anhydrous Clinker Hydration Products


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After the paste has gained strength, the reactions become diffusion controlled. Atthis 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 theset cement structure.

The above brief synopsis of the setting process emphasized the hydration of theC3S 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 similarhydration mechanism. The aluminates, though important in the early stages, arelargely halted in their reaction by the presence of available sulfates; and theircontribution to the final strength is minimal.

Since the volume of the hydration products is more than double that of the cementpowder the spaces between the original grains of cement are gradually, but notcompletely, filled. Once the cement slurry has set solid, hydration continues butrarely 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 thedegree of porosity – together with the strength and structure of the hydrationproducts – which governs the strength and other properties of the hardenedcement.

Porosity is dependent on the initial water/cement ratio – a lot of water will result ina high porosity and a low strength. Conversely, a low porosity hardened cementwill have a high strength.

Limitations of Cement

The performance of cements, particularly under elevated temperatures andpressures, will vary from cement plant to cement plant and from one manufacturerto another. This is due to variations in raw materials and in the actualmanufacturing process.

Other factors add further variability in the performance of cement slurries used inhydrocarbon producing wells. These slurries require chemical additives to modifythe properties to accomplish cementation of the casing under widely differentdownhole conditions. The inclusion of additives brings more potential fordiscrepancies in the response of cement slurries, since the chemicals themselvesare manufactured materials with their own potential for performance changes.


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The extreme temperatures themselves magnify the effect of compositionvariations. It is well known that the rate of chemical reactions dramaticallyincreases with temperature.

The result is that to prevent cementing job failures, slurries need to be testedusing the actual cement batch, field water and additives batches to be used in theactual 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 firstrecorded 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 sacksof neat Portland cement into the well. The procedure worked, and the treatmentbecame the accepted practice and soon spread to other California fields. Thedump-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 cementingprocess was born. The patent issued to Perkins specified two plugs.

Before 1940, wells were cemented using construction sacked cement mixed byhand using very few additives. In the 1930's no additives were used. However, aswells became deeper, more flexibility in cement performance was required thancould 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 thesearch for better cements for wells started. The API Sub-Committee 10 is still inexistence today and, in association with ISO, sets the current specifications for oilwell cements.


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An API cement is a cement that meets performance and chemical specificationsset by the API for the specific grade and class of cement. Today, there are eightAPI classes of cements each with distinctive characteristics and performance.

Five of these API classes are commonly used today by the oil industry, and threeused 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 littleelsewhere.

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 Specification10A, January, 1995.' The specific application for a given cement will depend onseveral factors including well location, downhole conditions and availability.

API Cement Specifications (Classes and Grades)

The American Petroleum Institute (API) sets specifications for the followingcement classes: As well as the Classes A, B, C, D, E, F, G and H the APIrecognises grades of sulfate resistance: ordinary, moderate sulfate (MSR) andhigh sulfate resistance (HSR).

Class A

Specification: The product obtained by grinding Portland cement clinker,consisting essentially of hydraulic calcium silicates, usually containing one ormore of the forms of calcium sulfate as an interground addition. At the option ofthe manufacturer, processing additions may be used in the manufacture of thecement, provided such materials in the amounts used have been shown to meetthe requirements of ASTM C 465. This product is intended for use when specialproperties are not required. It is available only in ordinary (0) Grade (similar toASTM C 150, Type 1).


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Intended Application: This cement is intended for use from the surface down toabout 6,000 feet, or to 170F bottom hole static temperature, when specialproperties are not required. Class A (ASTM Type 1) cement is manufacturedusing specifications applicable to the construction industry. The primary use inwell cementing is for surface pipe, or other applications of low temperatures andpressure. 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 ormore of the forms of calcium sulfate as an interground addition. At the option ofthe manufacturer, processing additions may be used in the manufacture of thecement, provided such materials in the amounts used have been shown to meetthe requirements of ASTM C 465. This product is intended for use whenconditions require moderate or high sulfate-resistance. Available in both moderatesulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades (similar to ASTMC 150, Type 11).

Intended Application: This cement is intended for use from the surface to 6,000feet, or to 170F BHST, where moderate or high sulfate resistance is required. Thiscement is manufactured according to more stringent specifications than Class Aand is similar to ASTM Type II. Class B is similar to Class A, but it contains lessC3A and is generally ground more coarsely. This causes longer thickening timesand slower strength development than Class A. This cement is recommended forthe 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 ormore of the forms of calcium sulfate as an interground addition. At the option ofthe manufacturer, processing additions may be used in the manufacture of thecement, provided such materials in the amounts used have been shown to meetthe requirements of ASTM C 465. This product is intended for use whenconditions require high early strength. Available in ordinary (0), moderatesulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades (similar to ASTMC 150, Type 111).


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Intended Application: This cement is also intended for use from the surface to6,000 feet, or to 170F BHST, where conditions require high early strength or highsulfate resistance. It is a common misconception that Class C cement cannot beused at depths greater than 6000 feet. In fact, slurries using Class C cementhave been designed and used successfully in West Texas and New Mexico atdepths in excess of 10,000 feet. The lighter slurry density (14.8 ppg) of thesecements sometimes gives Class C cement a distinct design advantage. Class Cis available in ordinary, moderate (similar to ASTM Type 111) and high sulfateresistance types.

Several manufacturers make Class C under different trade names. Through ironmodification, all are produced free of C3A which is the cement constituentattacked by the sulfate ion and whose absence renders cement highly sulfateresistance. 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-bearingflood waters for secondary recovery.

Class D

Specification: The product obtained by grinding Portland cement clinker,consisting essentially of hydraulic calcium silicates, usually containing one ormore of the forms of calcium sulfate as an interground addition. At the option ofthe manufacturer, processing additions may be used in the manufacture of thecement, provided such materials in the amounts used have been shown to meetthe 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 temperaturesand pressures. Available in moderate sulfate-resistant (MSR) and highsulfate-resistant (HSR) Grades.

Intended Application: Class D cement is intended for use from 6,000 to 10,000feet, or from 170F to 230F BHST where moderate temperature and pressureconditions are present. This cement is classified as one of the manufacturedslow-set cements and is no longer generally available. A "slow set" cement isdefined as a cement in which the thickening time was extended by (1) eliminatingthe rapid hydrating components in its composition or (2) by adding a chemicalretarder. Starch is commonly used as the retarder in Class D cements. Class Dcement has been replaced by Class G and Class H cements for mostapplications.


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Class E

Specifications: The product obtained by grinding Portland cement clinker,consisting essentially of hydraulic calcium silicates, usually containing one ormore of the forms of calcium sulfate as an interground addition. At the option ofthe manufacturer, processing additions may be used in the manufacture of thecement, provided such materials in the amounts used have been shown to meetthe 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 andpressures. Available in moderate sulfate-resistant (MSR) and highsulfate-resistant (HSR) Grades.

Intended Application: This cement is intended for use from 10,000 to 14,000feet, or from 230F to 290 deg F BHST, where high temperature and pressureconditions are present. This cement is also classified as one of the manufacturedslow-set cements and is not generally available. Lignosulfonate retarders arecommonly used in the manufacture of Class E cements. Class E cement hasbeen 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 ormore of the forms of calcium sulfate as an interground addition. At the option ofthe manufacturer, processing additions may be used in the manufacture of thecement, provided such materials in the amounts used have been shown to meetthe 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 temperaturesand pressures. Available in moderate sulfate-resistant (MSR) and highsulfate-resistant (HSR) Grades.


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Intended Application: Class F cement is intended for use from 10,000 to 16,000feet, or from 230F to 320F BHST where extremely high temperature and pressure

conditions are present. This cement is also classified as one of the manufacturedslow-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 ormore 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 foruse 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, thiscement 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 ormore 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 foruse 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.


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More on Classes H and G: The API Class G basic cement was developed in1964 and was specifically tailored for use in California. It was successful and theuse of it spread to the Rocky Mountain area. This success led to the developmentof API Class H basic cement in 1967 and was designed for use in the Gulf Coastarea where higher slurry densities were required.

The purpose of the development of these two classes of cement was to providebasic (neat) cements without additives, which would not vary in compositionamong manufacturers. They would be standard products that could beinterchanged in various slurries.

Class G and Class H cements are both manufactured to the same chemical andphysical requirements. The only difference is in the grind. Class H is groundmore coarsely than Class G and, therefore, requires less mixing water, resulting ina higher slurry density. The water ratios for these cements are 38 percent forClass 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 compressivestrength development, and result in excess free water within the cement column.This practice requires that careful laboratory testing be performed with the cementand additives prior to the job to make sure that the slurry and set cement possessthe required properties.

Other Commonly Used Cementitious materials

Pozzolans

Pozzolans (poz) are the oldest truly cementitious material. It is known that theRomans used natural (volcanic ash) pozzolans as a binding product in theirstructures. Pozzolans normally do not possess cement-like properties of theirown. However, when mixed with lime and water, they form compounds that dopossess cementitious value. Since lime is found in Portland cements and it is alsoliberated during the setting of cements, if pozzolans are combined with Portlandcements, the lime will react with the pozzolan. The pozzolan reaction depends ontime and temperature. It occurs slowly at temperatures below 140F, and fasterabove that value. Straight poz and lime slurries (no cement) have been use atelevated temperatures.


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It has been found that the addition of poz to cements is beneficial in reducingshrinkage, improving sulfate resistance, and in helping stabilize strengthdevelopments to temperatures near 270F. In addition, the inclusion of pozzolansreduce slurry density and cost. Cement slurries containing poz have other goodcharacteristics such as good rheologies, usually easy to mix, have low heat ofhydration (in situations like permafrost, high heat of hydration is not a desirableproperty), and can possess low permeability. Pozzolans slurries are good fillertype slurries due to their relatively low densities and high yields, They can also beused 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. Variabilityof the material can cause difficulty in slurry design and so many of the advantagesare outweighed.

When making calculations for the weight per sack of poz-cement blends, the APIguidelines and nomenclature need to be followed to avoid confusion and errors.In these blends, the content of pozzolan is based on the absolute volume ofcement replaced by the poz. Absolute volume is the volume of the material perunit of mass without voids. This should not be confused with bulk volume, whichincludes the air around the particles of the material. Bulk volume is used tocalculate storage requirements for bulk materials.

For example, a 35-65 blend means 35 % by absolute volume of poz and 65% byabsolute volume of Portland cement. In the API recommended nomenclature, thefirst number always refers to the poz, and the second to the cement. In thisexample, 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 theblend is calculated as follows. Notice that the API defines one sack of Portlandcement 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


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Notice that the calculations shown above define an equivalent sack of the blendas the weight of the blend in pounds that occupies the same volume as 94 lbs ofthe Portland cement being used.

Once the equivalent weight of a sack of the blend is calculated, the concentrationof additives included in the slurry design is based on that weight. For example, if0.2% retarder will be used, the weight of retarder per sack of the blends is 87.2 x0.2 = 0.174 lb.For laboratory and for filed bulk blending calculations, it is important tore-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 lbWeight 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 minimizeseveral of the quality control issues associated with the use of poz systems, andhave similar or improved properties over field blended fly ash slurries.

Trinity Lite-Wate

This high sulfate resistant cement is manufactured by the Trinity Division ofGeneral Portland, Inc. It is a blend of Portland cement and calcined shale. Thematerial is finely ground. Water content of the formulations can be varied fromabout 65 - 115 percent to generate high strength, lightweight slurries within arange of densities of about 11.9 - 13.7 lb/gal. The cement is available in bulk orpackaged 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 formulationsof slurries in a density range of about 11.9 to 14.2 ppg, using water rations of from55% to around 109%. It is a blend of Portland cement and calcined shale. Thecement 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, anddevelops good levels of compressive strength.


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Laboratory Testing of Cement Slurries

The API 'Recommended Practice for Testing Well Cements' (API RP -10B),provides recommended testing devices and procedures to measure theperformance properties of cement slurries to be used in wells.

Thickening Time

Thickening time often called "pumping time" is the time a cement slurry remainssufficiently fluid to be pumpable under downhole temperature and pressure. Thethickening time must be long enough to allow the slurry to be mixed and placedwithout risk of premature setting. Desired thickening times are based on theestimated job time to pump the fluids, plus a safety factor. Excessive thickeningtime should be avoided to eliminate lengthy WOC (waiting on cement) times.

The laboratory devices used to measure the thickening time of cement slurries aredefined in API RP-10B. Cementing laboratories throughout the world have thesedevices known as consistometers. The apparatus allows agitation of the cementslurry under simulated well conditions of temperature and pressure, whilemeasuring the consistency (an arbitary measure of viscosity) of the slurry.Depending on the design, a consistometer can simulate well conditions oftemperatures 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 continuousconsistency measurement is recorded. The end of the thickening time test iswhen consistency reaches 70 or 100 Bc. Bc is an API defined empirical unit ofconsistency named in honor of Bob Bearden, a departed industry researcher.Tests are often terminated once the cement slurry reaches 70 Bc to facilitateremoving 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 theunsung heroes of the oil-patch.

Although RP-10B provides "test schedules" for testing thickening times fordifferent well depths and temperature gradients, the test schedule for a given jobneeds to be calculated using the actual well conditions and the anticipated pumprates. The API schedules are ‘average circumstances’ and should be used onlywhen insufficient information is available. As soon as this information on theactual job is obtained, the test needs to be re-run using a job-calculated testschedule. API RP-10B provides information on how to calculate job-tailored


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thickening time schedules. For example, the length of time to pump the leadingedge of the cement slurry from the surface to the bottom of the hole (from thesurface temperature to the bottom hole circulating temperature), needs to becalculated using the capacity of the casing to be cemented and the expectedaverage job pump rate. Below is an example calculation of a job-tailoredthickening 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 thatthe well BHCT is the same as the one given by the API. In an actual case, thistemperature would be refined using a numerical simulator and maybe log infor-mation. 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 thesurface 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


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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, itis possible to adjust the tailored schedule to simulate the cement moving up theannulus. This is often not done since normally the circulating temperature at thetop of the column is not known. The RP-10B contains the equations needed tomake this schedule adjustment.

As can be seen, a well-tailored thickening time schedule can be quite differentfrom the "average" API schedule. If the cement slurry for the job is not testedusing a realistic schedule, this could lead to incorrect additive concentrations inthe final slurry, and in the worst scenario, job failure.

Fluid Loss

Cement slurries are frequently pumped across permeable zones with a positivepressure differential. As with muds, a positive pressure differential is maintainedto prevent a kick. Cement filtrate will pass into the formation even though a drillingfluid filtercake is present. A small amount of cement dehydration (loss of filtrate)is generally acceptable, but severe dehydration of the cement slurry will alter theperformance properties of the slurry including thickening time and rheology. Withdehydration, the cement will set earlier due to the lower water/cement ratio andthe loss of retarder. In extreme cases, cement can "block off" the annulusterminating the job. It is therefore important to control the fluid loss rate in cementslurries. The following conditions make control of fluid loss of the cement slurrymore critical:

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

• High zone permeabilities

• Large differential pressures, for example across depleted or partiallydepleted zones

• Narrow annular clearances, for example when cementing liners

• Poor mud properties

A well formulated mud system, even with a high overbalance of several thousandpsi, will produce a low permeability filtercake which will prevent loss of filtrate fromthe cement. It can be argued that, in many cases, the fluid loss control in thecement is an unnecessary added expense. However, it is well established


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practice to control fluid loss from cement slurries across permeable zones. A poormud cake will do little to control cement filtrate loss, but it will also hinder mudremoval and lead to poor isolation. Good fluid loss control in the cement will not fixthat!

Cement slurry filtration under pressure against a permeable medium is normallymeasured in the laboratory under static conditions with a high pressure filterpress, using API (RP-10B) established test procedures. The press is essentiallythe same used to measure fluid loss of drilling fluids. The significant difference isthat the filter medium is a No. 325 U.S. standard sieve series wire screen insteadof filter paper. Normally, the slurry is placed in a HPHT consistometer and theappropriate thickening time test schedule is followed. Upon completion of theschedule and an additional 30 minute conditioning period, the slurry cup isremoved from the consistometer and the slurry is poured into the pre-heatedhigh-pressure filter press. The filtration is maintained for 30 minutes at 1,000 psidifferential 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 onlog-log paper and extrapolating to the 30-minute value or by using the followingformula:

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 apparatusknown as the Stirred Fluid Loss Cell This is specialized equipment that combinesthe functions of a conventional, static fluid loss test cell, with the slurryconditioning capabilities of a consistometer. With the Stirred Fluid Loss Cell, theslurry 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 isconditioned at bottom hole conditions for an additional 30 minutes. After theconditioning period is completed, stirring is stopped, the cell is inverted, and the1000 psi pressure differential is applied in the normal manner for conducting afluid loss test. A procedural advantage of using this apparatus is that there is noneed to cool the slurry in the consistometer, to be able to remove it from thedevice, if the test temperature exceeds 190F.


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The main advantage of this device is that it simulates the cementing jobconditions more closely than when using the static cell. One disadvantage (thesame as for the static cell) is the limitation on working pressure, as mentionedearlier. Another shortcoming is that in reality, this is still a static, rather than adynamic test, because stirring of the slurry ceases prior to the application of thedifferential pressure, and the filtration test is run with the slurry under staticconditions.

Testing of the cement fluid loss at the BHCT is critical since fluid loss additives aretemperature 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 normallyused 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 as50 - 20 milliliters for cementing of liners, particularly if potential for gas migrationexistent.

Viscosity (Rheology)

Rheology is the technical term used to describe the shear rate - shear stressbehavior of a fluid.

The rheology of a cement slurry needs to be measured to allow predictions of thepressure drop and the flow regime of the slurry at projected job flow rates. Thesecalculations are normally performed using computers. In addition, the rheology ofthe slurry can help the experienced engineer decide if the fluid will be easy to mixin the field, and/or if the slurry will tend to segregate (settle).

The API document RP-10B contains two detailed chapters dealing with thedetermination of the rheological properties of cement slurries, and with methodsfor calculating pressure drop and flow regime in pipes and annuli.

Cement slurry rheology is normally measured using a portable, atmosphericpressure rheometer. Two different instruments are available. The Fann V-Gmeter and the Chan V-G meter. The two devices function in essentially the sameway. The maximum temperature than can be used with these rheometers isabout 190F.


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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 slurryand of the cementing job.

As an example, the Fann V-G Meter is a direct-indicating rotational-typeviscometer powered by a two-speed synchronous motor to obtain rotationalspeeds of 600 rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The outercylinder or rotor sleeve is driven at a constant rotational velocity for each rpmsetting. The rotation of the rotor sleeve in the cement slurry produces a torque onthe inner cylinder or bob. A tension spring restrains the movement. A dial attachedto 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 acement slurry may cause a viscometer fitted with a #1 spring to "peg out". Aspring 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 dialreadings are doubled to convert them to the readings that would have beenobtained using a #1 spring. In effect, a #1 spring allows readings to be taken from0 to 300 degrees while a #2 spring allows readings to be taken from 0 to 600degrees. Viscometers equipped with #2 springs are often used because theyallow more complete data to be collected for slurries that have higherconsistencies.


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Figure 7 shows the rheological behavior of a neat cement slurry measured using aFann VG meter. The shear stress - shear rate response was curved fitted usingthe 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 essentiallythe result of the hydrated structure discussed in a previous section. It is alsoinfluenced by the charges on the particles in the mix water. If a cement slurry isallowed to remain static for a period of time, it will gel to a degree that depends onthe formulation of the slurry, the temperature and pressure, the time since theslurry was mixed, and the length of time the slurry remains static. A knowledge ofthe gel strength development behavior of a cement slurry is important since if, forsome reason, the slurry becomes static in the well and develops high levels of gelstrength, it will take high pump pressures to break the gels. These high pressuresmay cause breakdown of weak formations in the well. In addition, static gelstrength development in the annulus causes a pressure drop in the cementcolumn. Depending on the magnitude of this pressure drop, and the fragility of thestructure in the cement, this may allow invasion of formations fluids into thewellbore.


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The API RP-10B recommended practices document gives a test procedure toestimate the gel strength development of cement slurries using the Fann or ChanV-G meter. The procedure utilizes the lowest speed of the instrument to measurethe gel strength (normally the 3 rpm). For purposes of comparison amongdifferent slurries and even for the estimation of the start-up pressures after a shortshut down period, this method is fine. However, for the estimation of the pressuredrop of a cement column to determine the time for potential fluid invasion of thecement 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 gelstrength development under downhole conditions needs to be made. The Fann orthe Chan V-G meters are not capable of measuring the gel strength developmentat the needed accuracy. These laboratory instruments can test fluids only atatmospheric pressure and at a maximum temperature of about 190×F. Inaddition, the 3 rpm speed (normally the lowest available speed with theseinstruments) is too high to measure true gel strength. This speed causes the gelsto break at the rotor interface, defeating the purpose of trying to measure thestrength of the weak gels as they develop. The measurement of gel strengthdevelopment needs to be made with the fluid static, taking great care not to breakthe gels as they develop.

Two methods are available to the industry to perform accurate measurements ofgel strength development. One is that developed by Halliburton know as theMACS. The MACS (Multiple Analysis Cement Slurry) Analyzer is a lab deviceused to measure the static gel strength characteristics of fluids vs. time, atdownhole 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 developmentof the static gels. This recently developed capability can be added to the UCA(Ultrasonic Cement Analyzer) which is used to measure the strength developmentof cements vs. time (the UCA is discussed later in this section).


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Figure 8: Gel Strength Development Using the MACS

Recently, Schlumberger has developed a version of the vane rheometer forsimulated downhole conditions. The device is not well known or readily availablethroughout the industry.

Free Fluid – formerly known as Free Water

Free Fluid is the liquid (water and dissolved chemicals) that separates from thebulk of the cement slurry under static conditions. The amount of free fluiddepends on several variables including the composition of the cement slurry, thetemperature, the mixing and conditioning history, etc. Its measurement isdependant on the method used. Again, the API RP-10B contains severalmethods to measure the separation of "free" fluid.

Free fluid is an indication of the stability of the cement slurry. Cement slurries withhigh levels of free fluid (normally ~2+% of the slurry volume) often tend tosegregate or settle out under static and/or dynamic conditions. This behavior canproduce cement columns that are non-homogeneous from top to bottom. Inaddition, in deviated holes, free fluid can generate a fluid channel on the high sideof the hole. This channel can easily allow migration of formation fluids along thecemented annulus.

0

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In the API “operating free water test,” the slurry is heated to BHCT (or BHSQT forsqueeze operations) in a pressurized consistometer in accordance with theappropriate schedule, cooled to 194×F (if needed) and then transferred into a250 ml graduated glass cylinder. If the free fluid test is going to be conductedabove room temperatures (maximum of 176 deg F according to API), thegraduated glass cylinder is placed in a pre-heated curing chamber or water bathfor the duration of the test. The cylinder is sealed to prevent loss of fluid throughevaporation, and then allowed to remain quiescent, on a vibration-free surface, forthe two-hour duration of the test.

In an attempt to determine free fluid under more realistic downhole conditions, thetest is sometimes conducted with the cylinder at an angle, particularly for highlydeviated or horizontal wells. Since the 45× angle is a severe case for free fluidoccurrence, 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 ashorter settling path for the cement particles.

The preferred free fluid content of cement slurries, particularly for critical wells iszero. This is particularly so for highly deviated or horizontal wells. For nearvertical wells, the maximum allowed free fluid content should be 1.0%, unlesspotential for gas or water migration after cementing exists. In that case, the slurryshould be designed for zero free fluid, regardless of the well angle, tested atconditions as close as possible to those to be encountered downhole.

Strength Development

The conventional way the oil industry has determined strength of cements is bymeasuring unconfined compressive strength on 2” cubes cured for differentperiods. This approach is borrowed from the construction industry and is a usefulcomparative method for different slurry types and designs.

The strength requirement for oil well cements depends on several factors. Ingeneral, the cement must have sufficient strength to secure the pipe in the hole,exclude undesirable well fluids, and withstand the shock of drilling, completingand subsequent production loads.


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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.


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API RP-10B includes two methods to measure the strength development ofcements. One is the destructive test referred to above using 2 inch cubes curedin moulds at simulated downhole conditions. The other uses a special deviceknown as the Ultrasonic Cement Analyzer (UCA). With this instrument, a sampleof cement is held in a pressure cell and subjected to insitu ultrasonic pulsevelocity measurement. Again API RP-10B test schedules are used to heat up thesample. Pressures used are generally about 5,000 psi, but the test equipmentcan be used to much higher pressures (as high as 20,000 psi).

Measurements of the cement's ultrasonic pulse velocity are started during thefluid state and continue through the initial set to any desired time. Strength valuesare continuously computed and displayed until the test is terminated. The result isa complete history of the initial set and the strength development. Figure III-8gives an example of the UCA test.

The principal advantage of the UCA is that it allows determination of compressivestrength continuously vs. time. In addition, the measured transit time of thecement can be used to help "fine tune" ultrasonic devices used in the field todetermine the condition of the cement behind the pipe. Other advantages aresimplicity of the test, and the low level of labor required. Once started, the devicecan be left to collect data for long periods of times without attention. The maindisadvantage of this method is that the compressive strength of the cement isinferred from correlations developed between transit time across the sample andcompressive strength. Three correlations are generally programmed in theinstrument for low, medium and high density/strength cements. At the start of thetest, the technician selects the correlation to be used. Pulse velocity is every bitas useful a measurement as unconfined crush tests.

In general, the predictions of strength development when using the UCA, whencompared 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 thecube method at the same curing conditions.

With either one of the methods described above, curing schedules and testparameters need to be adjusted to reflect as closely as possible the conditions ofthe well. For example, the testing schedule should be modified as needed to beable to measure the compressive strength development of the cement at the topof the cement column. The API RP-10B gives guidelines to accomplish theseschedule adjustments.


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Figure 9: UCA Test: example chart

Settling Behavior

Solid segregation, or settling, downhole under static and/or dynamic conditions isa serious concern in drilling operations. Barite sag is well recognised in theindustry and poorly designed cement slurries and spacer fluids can behave in asimilar manner. The concerns occur particularly in highly deviated and horizontalwells. 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


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Some investigators have thought that settling occurs mainly while the fluids arestatic in the well. Although static settling occurs, other work indicates thatdynamic 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 underdownhole conditions of temperature and pressure.

Static Settling Test

API RP-10B describes a static settling test that is widely used throughout theindustry. In essence the test consists in placing a sample of cement slurry in atube and allowing the cement to set under downhole conditions. The depth to thetop of hard cement is measured and then the tube is split to allow removal of theset cement column. The column is then cut into sections and the density of thedifferent 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 viewof segregation or settling. The Figure shows a sketch of the API sedimentationtube.

Settling Test Tube

The main advantage of the API test is that it is quantitative in nature. The user isable to "measure" the settling or segregation tendencies of the fluid. The otheradvantage is that the method is very well known throughout the industry often asthe ‘BP Settling Test’.

The main drawback is that it takes time to obtain the results of the test. Thecement 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 isapproaching.

Another test method uses a consistometer to bring the cement slurry to downholeconditions 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 30minutes, and without re-stirring, the slurry is removed from the tests apparatusand examined for static settling. Measurements of the density of the slurry aremade at several depths in the slurry cup to try to quantify the setting/segregationtendencies of the slurry. The bottom of the cup is carefully examined looking forsettled/segregated solids. This procedure has been very successful in detectingstatic settling/segregation of cement slurries, spacer and drilling fluids.


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The main advantage of this method is time, taking even less than a thickeningtime test. Because of the size of the slurry cup, the tests is not affected by walleffects.

Dynamic Settling Test

Dynamic settling (settling during pumping of the fluid) can be critical especially inhighly deviated, ERD and horizontal wells if the potential for gas or water invasionexists.

Tests have suggested that it is possible for a cement slurry to show very little staticsettling, but have serious dynamic settling. One possible explanation for thisphenomenon is that statically, the fluid is allowed to develop gel strength whichcontributes to solids suspension. Under dynamic conditions, gel strength is notdeveloped, and if the fluid does not have enough viscosity at downholeconditions, solids may settle out. Low flow rates will exacerbate the problem.

The API RP-10B does not contain a dynamic settling test. However a procedurewhich was developed by a major oil company is available. Service companies arefamiliar with the test and are capable of performing it.

The laboratory procedure requires a variable speed consistometer equipped witha special slurry cup paddle that allows detection of dynamic settling. The fluid isbrought to downhole conditions of temperature (BHCT) and pressure using athickening time schedule, stirring at 150 rpm (normal rotation speed). Once thecement slurry is stabilized at bottom hole circulating temperature and pressure,the rotation speed of the consistometer is reduced to 20-30 rpm. Rotation at thelow rpm is continued for a minimum of 30 minutes then the cup is removed fromthe consistometer and opened without turning it over.

The standard cement slurry cup paddle is intended to maintain the entire slurryagitated and homogeneous. The paddle used to detect dynamic settling likewisekeeps the fluid stirred throughout the entire cup at high rpm, but allows solidssettling at the low rpm


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Once settling starts to take place, this is apparent on the consistency chart. Thesolids at the bottom of the cup start to load and grab the paddle and the recordedconsistency starts to increase or to look “jagged”. The final confirmation of theexistence or nonexistence of settling is after the test, when the slurry cup isopened and the fluid examined for settling. The height of the cone of solids at thebottom of the paddle is measured and recorded. A true non-settling fluid will notform a cone on the bottom plate of the paddle (zero cone height). The maximumcone height normally allowed is 1/2 in. Another criteria is that for lightweightslurries, more than 1/2 lb/gal difference from top to bottom of the cup is notaccepted. For weighted slurries, more than 1 lb/gal difference from top to bottomof 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 mod-ified to suit the aims and objectives of the job.

Understand the function of cementing additives and when it is necessary to usethem.

Become familiar with the laboratory test methods, test equipment and the inter-pretation 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 frac-turing weak formations

• Fluidity to enable pumping and placement

• Setting time, or pumping time, so that the slurry sets soon after the job iscomplete and the subsequent operations can begin.

• Strength – this may or may not be important. A kick-off plug may need ahigh 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 – andprevent 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 balancebetween opposing trends. On the one hand, low water to cement ratios generatedense, high strength set cements. Test have suggested that the maximumcement strength is obtained at a water-cement ratio of about 2.8 gallons of waterper sack of cement. This is the minimum amount of water necessary to fully chem-ically react and hydrate the cement particles.


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However, this cement-water slurry would have the consistency of caulk, or tooth-paste, and could not be pumped down a well. On the other hand, high water tocement ratios reduce slurry density and give low slurry rheologies that facilitatemixing, reduce frictional pressures and allow pumping with field equipment. Toomuch mixing water de-stabilizes the slurry, causing free fluid and settling/segrega-tion of the particles. In addition, high water to cement ratio slurries produce lowstrengths. Therefore, one of the primary slurry design issues is the balancebetween density (usually determined by the well circumstances) and the fluid andset properties.

Quality of the Mixing Water

Whenever possible, potable (drinkable) water should be used to mix the cementslurry. However, fresh waters are not always available. For example, offshore, seawater is often used to mix the slurry. In remote locations, low quality (contami-nated) water may be the only source available. In many cases non-potablewaters can be used with care, but the slurries must be lab tested using the actualfield water to be used in the job. Additive concentrations and response will varydepending on the water source.

Field waters sometimes come from open pits or from shallow water wells, streamsor lakes. These waters are often partially contaminated. Contaminants in mixingwaters 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 andother properties of the cement slurry.

Density

The well design will normally fix a range for the slurry density. This will be influ-enced by the height to which the cement is to be lifted, e.g. 500ft MD inside theprevious shoe, and the available pore/fracture pressure window. The slurry den-sity will normally be higher than the mud density. A lead and tail system (a lighterslurry followed by a heavier slurry) may be used to reduce total pressure at theshoe 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 waterper sack of cement (94 lbs) and as percent water (pounds of water per 100pounds of cement).


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The slurry density and yield are also given in the table. The slurry density isshown in pounds per gallon and the slurry volume (yield) in cubic feet per sack ofcement.

Figure 10: API Normal Cement Slurry Densities

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

• Increasing the water/cement ratio

• Including light weight particles – particles with a density less than thecement

Fluidity

The ability to mix the cement slurry on the fly, or in a batch mixer, is obviouslyimportant. In addition, the cement slurry must be placed in the annulus withoutexcessive friction pressures that may exceed the fracture gradient. Conversely, ifthe 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 displace-ment/placement efficiency consideration discussed later. When necessary, therheology 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 setfast once in place. Cement needs to develop strength fast to support and protectthe pipe, and for the drilling engineer to be able to proceed with drilling or comple-tion. So, a controllable thickening time is needed.

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



Cement Manual

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

Sufficient Strength

Cement needs to develop strength to protect and support the pipe, and to allowsubsequent operations in the well. However, just how much strength is needed forproper 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 sothis is good insurance. However, high strength cements are brittle, and recentstudies have suggested that the industry needs to consider using lower strengthcements (below 2000 psi) across pay zones. Some of these lower strengthcements are better able to withstand casing perforating and loads imposed bypressure and temperature changes in the wellbore, without damage to their integ-rity.

The poor understanding of strength requirements is, in part, due to the very sim-plistic crush test used in the industry. This unconfined 2” cube test is really only ofany use as an indicator of strength development and as a means of comparing dif-ferent samples. The numbers generated are not useful in design calculationswhere complex loading needs to be addressed.

The strength development of cements depends mainly on temperature and thewater/cement ratio.

Low well temperatures tend to cause slow strength development. This can pre-sents a serious design challenge for shallow casing strings and/or low tempera-ture environments like the North Slope and in deepwater locations. On the otherhand, elevated temperatures accelerate the development of strength.

At temperatures above about 230F, powdered silica needs to be added to thecement to avoid the phenomenon known as ‘strength retrogression’.

The compressive strength development of the slurry is normally measured onlyafter the other properties have been determined and optimised. If the strengthdevelopement is acceptable, the cement slurry formulation is considered satisfac-tory.

No Permeability

Protection of casing and prevention of fluid migration within the cemented annulusduring the life of the well requires set cements to have very low permeability oncefully set. Fortunately, cements normally develop very low levels of permeability.The Table below shows examples of permeability values for several neatcements.



Cement Manual

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

(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 permeabili-ties, much lower than those of producing formations and similar to those ofshales. However, the final permeability of a cement is a property over which nor-mally, relatively little control can be exercised. The API RP-10B contains a proce-dure to measure the permeability of set cements but, under normal conditions, notmuch attention is given to the permeability of the set cement, and permeabilitiesare not often measured.

Cements subjected to high temperatures – higher than 230 deg F – which havenot been stabilized against strength retrogression will show increased permeabili-ties 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

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



Cement Manual

No Shrinkage

Shrinkage is perhaps the most misunderstood and controversial property of oilindustry cements. The main reason is that the problem is complex. The API haspublished a pamphlet (API Technical Report 10 TR2) on expansion/shrinkage ofcements that attempts to explain the phenomenon and better define the terms.

Shrinkage and expansion of cements results from the formation of hydration prod-ucts having densities which differ from those of the reacting components. Thesehydration 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 inextra fluid or gas from the surroundings. When cements are sealed in totallyimpermeable 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 againstpermeability – say a water bearing sand – and extra water can be sucked into thesample as the hydration proceeds, then the total of the inner and bulk shrinkage isaround 6%. This inner, chemical, shrinkage is related to the development of inter-nal 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 whichmeasurement starts. If cement is mixed with water, conditioned, then sealed in amembrane while it is still a pumpable slurry; then the bulk volume change, mea-sured 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 andthen the measurements are started then the cement is seen to be expansive (seethe new origin ‘Time Zero’ on the curve).



Cement Manual

For cement inflated packers, cement shrinks and the sealing has to be compen-sated for by the rubber. In a normally cemented annulus, early shrinkage may becompensated for by movement (compaction) of slurry.

The negative pressure developed during hydration of the cement can draw in gasfrom the formation. This effect, coupled with other properties of the slurry, canlead to gas migration and an incomplete annular seal.

So-called expanding cements should only be used in extreme cases and wheretheir behaviour is understood in detail. When an unrestrained annular ring ofcement expands, the hole in the centre gets bigger not smaller. In a weak forma-tion, cement expansion can produce a micro-annulus.

Long term durability

One very substantial benefit of cement is that it has an established track record fordurability – both in the oil industry and the construction industry. The mechanismsof degredation are well understood and, in general, cement once placed and setwill 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 defenceis a low permeability – this is obtained through reduced water content and throughthe use of particles within the slurry, e.g. latex.

Expansion

Contraction

Log time

liquid

solid

Mix with water and start measurement while still a liquid

Time zero



Cement Manual

Strength Retrogression at temperatures higher than 230 deg F – addressed bythe addition of silica

Severe cycling of pressures and/or temperatures – this can lead to cracking andeventual 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 thecement 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 sealingwellbores. Long term integrity of cements is well proven and, in general, the integ-rity of hydrocarbon producing wells has been satisfactory. This has been the tes-timony from operators who have used cement in thousands and thousands ofwells throughout the world with good results. There are other materials that couldbe considered, for example some resins and various inorganic systems, but thesematerials 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 useof cement in the construction industry. It is relatively easy for a cement plant pro-ducing construction cement, to also be able to manufacture API type cements.Many cement manufacturers throughout the world are producers of mono-grammed 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 downholeconditions.

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 inten-tion is to reduce or increase the slurry density. Often these density controllingadditives require additional water to be included in the formulation to maintain thedesired consistency, or the use of some concentration of dispersant.



Cement Manual

Adjusting the Water Concentration to Change Slurry Density

The simplest way to modify the slurry density is by changing the water to cementratio. For example, densified slurries can be designed by reducing the water con-centration to levels that can produce densities of around 17 - 17.5 lb/gal withoutthe need of adding high density additives to the formulation. On the other hand,light density slurries can be designed by increasing the water concentration fromthe 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 usedin the design of light weight slurries. The clay hydrates and allows high concen-trations of water to be used while still maintaining good slurry consistencies andslurry 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 qualitybentonite is about 6 pounds of water per pound of bentonite when the bentonite isdry blended with the cement. If the bentonite is fully yielded by prehydrating itwith the mix water and then using the bentonite-water slurry to mix the cement, itis possible to approach the level of 11 lbs of water per pound of bentonite. Thenext table gives examples of some slurry formulations using bentonite.

Class G Cement with Bentonite

Figure 13: Dry Blended:

(1)Percent by weight of cement

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



Cement Manual

Figure 14: Prehydrated:

(2)Percent by weight of cement

Sodium Metasilicate

Sodium Metasilicate is available as a dry powder for dry blending or as a liquid formixing in the cement mixing water. Most of the Sodium Metasilicate used by theindustry is in the liquid form. This material is capable of taking-in large volumes ofmixing water, allowing slurry densities down to 11.5 lbs per gallon to be mixed withlittle to no free fluid separation. Although the additive is a mild accelerator, at thelow densities, the strength development of the cements is quite poor. This mate-rial should not be used at temperatures above about 150 F because conventionalretarders needed at high temperatures tend to destroy the effectiveness of theadditive. In addition, salt concentrations about 5% by weight of water (bwow)should not be used with this material. Some slurry formulations using SodiumMetasilicate are shown in the following Table.

Figure 15: Class H with Liquid Sodium Metasilicate - Fresh Water

Percent Bentonite(2)

Mix Water gal/sk

Slurry Weight lbs/gal

Slurry Vol-ume 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

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



Cement Manual

Using Particles to Lower Slurry Density

There are several materials that can be used to reduce slurry density. We willreview several of the most commonly used.

Hollow Spheres

The most commonly used hollow spheres are fly ash 'floaters', a by-product of thecoal burning process. The material has an specific density of about 0.685 atatmospheric conditions, and a bulk density of about 25 lb/cu.ft. The use of thisadditive allows cement slurry densities as low as 10 lb per gallon with reasonablestrengths. Cement compositions containing hollow spheres are hard to design, tomake sure the spheres do not float out of the slurry. The recipes are also hard toblend due to the light density of the spheres. In addition, because increasingpressures tends to collapse portions of the spheres, the density and yield of theslurries change with pressure. The currently used hollow spheres are competentto about 6,000 psi.

Nitrogen - Foam Cements

Nitrogen has been used to generate foam cement slurries in the oil industry forover 20 years. Initially, the primary application was solving severe lost circulationproblems almost exclusively on land wells. The main benefit was providingultra-lightweight cement systems that could be applied at densities of less than 11lb/gal and gain good strength rapidly. Application of foam cement then grew toinclude squeeze cementing of weak zones which would not hold a column of con-ventional cement without going on vacuum during the job.

More recent applications have included prevention of water flows when cementingsurface casing in deep-water applications in the Gulf of Mexico and other areas ofthe world. Foam cements provide a means of placing a light, competent cementacross weak formations, with minimum losses. Additionally, foam cements havethe unique property of “compressibility-maintained, hydrostatic pressure” acrosshigh pressure gas and water zones, as the cement goes through the transitionfrom a liquid to a solid. Foam cements have overcome the problems associatedwith conventional cements for this application. Conventional cements are notcompressible and readily loose hydrostatic pressure while going through the tran-sition 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 duc-tility, to eliminate cement failure caused by temperature and/or pressure changesduring the life of the well. Conventional cements have been found to fail (crack)under those conditions. Physical properties and some advantages of foamcement technology are outlined below.



Cement Manual

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 baseslurry (unfoamed) is typically a conventional high strength cement. The additionof nitrogen (gas typically used to generate foam cement) does not reduce theoverall strength of the system to the extent of other lightweight additives used incement (excess water, microspheres, etc.). Foam cements can be generated atdensities much less than conventional lightweight cements with sufficient strengthfor completion purposes. Because of this, foamed cement can be placed in a sin-gle stage without loss of circulation in situations where conventional cementscould not.

2. High Viscosity: When a fluid is foamed it typically develops significantly higher vis-cosity than the unfoamed base fluid. Because of the highly energized nature andviscous nature of foam cement fluids, better mud displacement can be expectedwith foam cement in comparison to conventional cement systems. Better muddisplacement can ultimately mean better protection of the casing and sealing ofthe annulus, helping to eliminate costly squeeze cementing operations and otherrepair work.

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

4. Compressibility and Fluid Loss Control: The gas phase of the foam cementcauses the unset slurry to have significantly more compressibility than conven-tional cement slurries. Also, foamed fluids by nature have a degree of built-in fluidloss control. Both of these properties can help prevent gas and/or fluid migrationinto a cemented annulus. Gas migration can occur when overbalance pressureacross a gas and/or fluid bearing zone is lost. Overbalance pressure is lost due tothe combined effect of fluid loss, gel strength development, and the compressibil-ity of the cement slurry. Because foam cement is compressible (i.e. minimal pres-sure loss with a given amount of fluid loss) and has built-in fluid loss control, theloss of pressure in the annulus is minimized while the cement is setting up. Thisminimization of pressure loss aids in the prevention of annular gas and/or fluidinvasion.

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



Cement Manual

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 maintainthe desired fluidity),

• exhibit no significant strength reduction (due to dilution of the cement perunit 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. Eventhough it has a relatively high specific gravity, (5.02), the small particle size of theground additive helps keep it suspended in the cement slurry. Hematite high den-sity slurries also contain some dispersant to maintain a good solids-suspendingconsistency without having to add much water to the formulation. Slurries weigh-ing up to 20 lbs per gallon have been mixed and pumped with this additive.

6 lb/gal 8 lb/gal 10 lb/gal0

200400600800

10001200

Str

eng

th (

psi

)

6 lb/gal 8 lb/gal 10 lb/gal

Class G Cement @ 100 °F

12 Hour 24 Hour 72 Hour



Cement Manual

Figure 17: Hematite Slurries With Class H Cement

Figure 18: Hematite + 35% silica flour

Barite

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

HematiteLbs./Sk

Water Gal./Sk.

WeightLbs./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

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



Cement Manual

Manganese Oxide

Recently, manganese oxide (hausmannite) has been used as a cement additiveto 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 itsfineness, the additive can be added directly to the cement mixing water, and it willremain in suspension. This property facilitates mixing of heavy slurries offshore,on the fly, without having to dry blend. Combinations of Hematite and ManganeseOxide have been used to design ultra heavy slurries at densities up to 23 lb/gal forultra high pore pressure environments in some areas of Colombia.

Adjusting the Slurry Rheology

Dispersants are chemicals that are included in cement slurry formulations toimprove fluidity. Dispersed slurries exhibit lower viscosities and therefore areeasier to mix and can be pumped at lower pump pressures, thus lowering thehorsepower 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 dispersantsare in the range of ~0.2% to ~1.5% based on the weight of the cement. In addi-tion to lowering the viscosity, these products impart a low level of retardation to thecement slurries, particularly at low temperatures. Dispersants are included in slur-ries to be exposed to a wide range of temperatures, from low conditions (60F), tovery high levels (350F). Often the dispersants are used mainly to allow mixing ofthe cement.

In general, dispersants are compatible with most other additives, and can be usedin many slurry formulations, with few problems. One exception is systems con-taining high concentrations of sodium chloride (above about 15%). With saltedslurries, the dispersants may tend to initially thin the slurries, but after a few min-utes, the slurry may flocculate, producing large increases in viscosity.

One caution that must be observed with dispersants if to make sure the slurry isnot 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 ofretarders or accelerators, depending on the well temperatures.

Accelerators are normally inorganic chemicals that speed up the reactions ofhydration of the cement. Since acceleration of the set time of cement slurries isnormally not needed unless the well temperatures are low, these additives arenormally not used at temperatures above about 100F. Slurry acceleration is usu-ally needed for the cementing operations of conductor and/or surface pipe to



Cement Manual

reduce WOC time and rig time costs. The most commonly used and effectiveaccelerator is Calcium Chloride. Many other inorganic materials can accelerateslightly. Sodium Chloride is a good example and seawater another.

Retarders are usually organic chemicals that retard or slow down the reactions ofhydration of cement systems. Extension of the set time is normally needed for thedeeper casing strings. Retarder materials include lignosulfonates, some organicacids and sugar derivatives. Cellulose derivatives used to help control the fluidloss of cement slurries also perform as retarders at low to moderate temperatures.At elevated temperatures, lignosulfonate retarders are stabilized by the addition ofborax.

Controlling Slurry Fluid Loss

Low fluid loss cement formulations have application in squeeze cementing opera-tions, and during primary cementing across narrow annuli, under high differentialpressures, and particularly for controlling gas migration after the cement jobacross gas and water zones.

Many fluid loss additives are cellulose based. Because of this, they tend toincrease the consistency of the slurry, and in addition, they also increase thethickening time of the formulation. The degree of retardation depends on the con-centration of the additive, and the well temperatures. Often dispersants need to beadded to adjust the fluidity of the system. Dispersants tend to enhance the effec-tiveness of cellulose base fluid loss control additives. Latex materials are alsoused to control fluid loss in cement slurries. .

Imparting fluid loss control to slurries containing calcium chloride or sodium chlo-ride for low temperature applications is a difficult task. Fortunately, there aresome fluid loss control additives available that are compatible with sodium chlo-ride 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 reachand horizontal wells, and in any situation with potential for gas/water migrationafter cementing. For these applications, designing for slurry stability becomesextremely important.

The conventional way to control this slurry property is by designing the slurry withvery low to zero free fluid with a rheology that facilitates mixing and placing. At thesame time, the rheology needs to promote suspension of the solids at static anddynamic conditions, and under downhole temperatures and pressures. Conven-tional materials such as bentonite that can be used to help suspend solids but theindustry has developed additives that do not increase viscosity at the surface –thus facilitating mixing - but that 'yield' under temperature, as the sluury is goingdownhole.



Cement Manual

Using Loss Circulation Control Additives in Cement Slurries

Losses of whole mud or cement slurry to natural or induced fractures or vugs dur-ing drilling or cementing operations are referred to as 'lost circulation' or 'lostreturns'. Lost circulation should not be confused with filtration loss (seepage),which normally occurs due to pressure differential across the permeability (filter-cake formation and dehydration through the filtercake).

Lost circulation problems during drilling need to be solved before starting thecementing operation. However, it is not uncommon to again experience losesduring the cement job, if weak zones are present. Minimization of these problemsmust be addressed during the planning of these jobs. Some materials that can beincluded 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 distributionof particles ranging from coarse (1/4 in.) to a fine powder. The coarser particlesbridge the fracture and the smaller particles then pack in around and over thelarger particles to complete the shut-off. The most commonly used granular addi-tive is Gilsonite. Another granular material available is ground walnut shells soldunder 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 effi-ciency of the additive. Normal concentrations of walnut shells used range from 1to 5 lbs per sack of cement.

A third lost circulation additive containing granular materials is sold under thename of 'Kwik Seal'. It contains fibers in addition to granular material and is alsoavailable in three grades, coarse, medium, and fine. Normal concentrations usedin cement slurries range from 1 to 3 lb/sk. Higher of concentrations of 5+ lb/skhave been used in specific instances across depleted zones in Trinidad. As for alllost circulation materials, at the higher concentrations, it is important to make surethat the float equipment is not plugged by the additive and that mixing and surfaceequipment can cope.



Cement Manual

Flaked Materials

The lost circulation control additive most commonly used in cement slurries is cel-lophane flakes. The flakes perform better when used across unconsolidated orhighly permeable zones where the lost circulation material can plaster over thethief zone. The flakes are not as efficient across fractured zones as the granularor fibrous materials. Cellophane flakes are usually used in concentrations rangingfrom of 1/8 to 1/4 lb per sack of cement.

Fibrous Material

These lost circulation additives are usually short nylon or polypropylene fibersused in concentrations of 1/8 to 1/4 lb per sack. These materials are best suited tobridge off narrow fractures. Normally these additives are used in combination withgranular or flake materials. Bulk handling of the dry cement with fiber added istroublesome, and special handling procedures for adding the fiber at the mixingtub are often needed. Fibers can also be used to keep the cement together incase it is damaged (cracked) downhole.

Effects of Extreme Temperatures

Strength retrogression at temperatures above about 230 deg F is prevented bythe addition to the slurry formulation of 35% fine crystalline silica (silica flour or sil-ica sand). The silica actively enters into the reactions at these temperatures, gen-erating reaction products that exhibit high strength. Silica is also added toslurries used to cement surface casing strings in HPHT wells. This is becauseduring production the cement will be exposed to temperatures above 230F. Dataindicates that strength retrogression is possible, depending on the temperatureand recipe used, with cements that have set at low temperatures, but are laterexposed to elevated temperatures above 230F.

Special Situation - Deep, Long Liners

The design of deep long liners is normally complicated by the extreme differentialtemperatures encountered from the bottom to the top of the liner. It is not uncom-mon to find situations where the circulating temperature at the bottom of the linermay be higher by as much as 50F or more than the static temperature at the topof the liner. In these situations, waiting on cement times may be extended inmany cases to 48 and even 72 hours to allow the top of the column to set. Incases of extreme temperature differentials, stage tools have been used because ithas not been possible to design a cement slurry capable of having the requiredthickening time at the BHCT, and also be capable of setting up in a reasonabletime at the top of the liner.



Cement Manual

Special Situation - Geothermal Wells

Although geothermal wells are usually completed in the same manner as conven-tional oil and gas wells, the environment is more severe. The bottomhole temper-ature in geothermal wells can be as high as 700°F, and the formation brines areoften extremely saline and corrosive. Many failures in geothermal fields havebeen directly attributed to cement failure. In geothermal wells, the temperaturesalways exceeds 230°F. Studies have shown that at least 35% silica flour isrequired to minimize strength retrogression. However, in geothermal wells wherevery high amounts of CO2 may be present, it has been suggested that reducingthe silica flour concentration from 35% to 20% may improve cement resistance toCO2 attack. However, these formulations need to be carefully tested in the labo-ratory at the expected well conditions.

At present, geothermal well cements are usually designed to provide a minimumof 1,000 psi compressive strength, and no more than 0.1 md water permeabilityin 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 underconditions similar to those in geothermal wells, the following guidelines weredocumented for slurries to meet the above requirements:

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

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

• The active solids-to-liquid ratio (by weight) should be 2.0:1 or greater.

• Slurry density should be reduced using microspheres or by creatingfoamed cement with nitrogen.

• Foam quality should not exceed 30%.

• Special CO2 resistant systems stabilized with silica can be used to obtainextremely low permeabilities and good strength.

• Latex slurries can be used to prevent gas migration as long as placementtemperatures 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 Manual

Special Situation - Ultralow Temperatures (Permafrost Zones)

Permafrost zones in areas such as Alaska and Northern Canada present someunique cementing difficulties. Permafrost is defined as any permanently frozensubsurface formation. Frozen formations extend to depths greater than 2000 ftand 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 ofhydration to prevent thawing of the permafrost, must not freeze and be able todevelop sufficient compressive strength at temperatures as low as 20°F. Conven-tional cement systems are not satisfactory in permafrost conditions because theyfreeze before developing sufficient compressive strength.

Special cements such as gypsum/Portland blends with sodium chloride as a mixwater freezing depressant, are used extensively for permafrost cementing. Forsurface pipe, these slurries are designed for 2 to 4 hours pumping time, yet theirstrength development is quite rapid and varies little at temperatures between 20and 80F. A typical composition consists of a 50:50 blend with 12% salt. The gyp-sum sets and gains strength rapidly at freezing temperatures, and protects theslower setting Portland cement from freezing. These cements also have a lowheat 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 forcementing 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 wastraced to flow of the salt formations. It was theorized that the cement slurrieswere leaching salt from the formations during and after placement, creating voidsbehind the pipe, facilitating the flow of the salt. It was expected than when anon-salted slurry was placed across a salt horizon, dissolution of the salt occurredat the cement/salt interface due to ion exchange, and poor zonal isolationresulted. This dissolution of salt formations has been confirmed with laboratoryexperiments. In contrast, excellent bonding at the interface cement/formation hasbeen observed with salted slurries. In laboratory tests, shear bond strengths weremeasured at the interface using slurries with varying salt concentrations. Theresults showed that improved interface contact occurs with increasing salt con-centrations in the cement.

Although no dissolution occurs when a salt-saturated slurry is used, these slurriesare quite difficult to design with the desired properties of compressive strengthdevelopment, settling, free water, fluid loss, etc. For this reason, cement slurriesused across salt formations often contain about 18% salt.



Cement Manual

This practice allows better control of the slurry properties, and has produced goodresults. In addition, many of the cement recipes are designed with potassiumchloride instead of sodium chloride. Lower concentrations ( 3 to 5%) of KCl canbe used with similar results, and KCl slurries are easier to design. The problemhas also been helped by the development be the service companies of specialpolymers (for example Schlumberger's Saltbond).

Another benefit of using a salted system across salt formations is that the designis 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 increasewith increasing concentrations of salt. The time required to develop adequatecompressive strength also generally increases with increasing salt concentra-tions. Because of this strength retardation effect, when designing slurries to beplaced across fast moving salts, the overriding consideration is to design theslurry such that it will develop adequate compressive strength as fast as possible.Often in these fast moving salt situations, heavier/thicker casings are used, alongwith accelerated cement slurries, with minimum thickening times and lower safetyfactors, to get the cement to set fast, before the formations have time to contactthe casing string, to minimize damage to the pipe.

A few years after starting to use salt in slurries across salt formations, it was alsoobserved that remedial squeeze cementing operations were improved (fewersqueeze stages required) when produced salt water was used for mixing cementin the western areas of the State of Texas, U.S.A. Investigators determined thatthe salt in the mix water was less disruptive and damaging to bentonitic sands andto shale beds, and produced a better cement bond to the shale. It was alsoobserved that salt concentrations less than saturated, 10% to 18% based onweight of the mix water, were sufficient to protect freshwater sensitive formations.Later, 3% to 5% potassium chloride was found to be equally effective, and againthese lower concentrations of KCl were less destructive to the effectiveness of thefluid loss control additives and facilitated the design of the slurry formulations.

Finally, a word of caution. High concentrations of salt in cement slurries need tobe used only when necessary (KCl is preferred over NaCl because of the lowerconcentrations and reduced negative effects). It has been shown that the use ofsalted cement slurries across fresh water formations can be very detrimental tothe long term stability of the cement. Due to the differences in ion concentrations,dissolution/osmotic forces can eventually destroy the integrity of the cement.



Cement Manual

Detrimental Effect of Magnesium Salt Containing Formations

Some salt formations contain very mixed salts and some contain MagnesiumChloride. The seriously detrimental effects of magnesium chloride on cement hasbeen well documented. Magnesium chloride attacks calcium hydroxide (freelime) in the cement forming calcium chloride, and causes decay of the calcium-sil-icate-hydrate (C-S-H) structure of cement (formed during hydration) throughleaching of the calcium by chloride ions. The cement is further weakened duringthe process by the formation of expansive compounds such as chloro-aluminatesand brucite (magnesium hydroxide). The cement is therefore attacked both chem-ically and mechanically. It should also be noted that if the slurry becomes contam-inated with magnesium chloride during placement, serious viscosity increases canoccur and the thickening time of the slurry can be significantly reduced. This vis-cosification is caused by the precipitation of magnesium hydroxide. It has beennoticed that contamination of cement slurries by less than 5% by weight of water(bwow) of magnesium chloride can reduce their thickening time by more than50%. It has also been found that attack by magnesium chloride can be averted orminimized 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 chlo-ride

If magnesium brines are to be encountered in formations along the interval to becemented, the best practice is to use a magnesium resistant system. In addition,compressive strengths and contamination tests should be performed on the slurryusing 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 blastfurnace slag to which 28% fly ash and 15% salt (sodium chloride) are added. Theblended product is mixed at a density of around 15.8-16.0 lb/gal. This cementwas successfully used across 11,850 ft of massive salt in a Netherlands well inthe Dutch North Sea where the presence of magnesium chloride was expected.Other available magnesium resistant systems incorporate latex and special poly-mers.

Detrimental Effect of Sulfate Waters

Formation brines containing sulfates are among the most destructive downholeagents to Portland cements. The deterioration is usually characterized by expan-sion, 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 NorthSea, and other oil producing area of the world.



Cement Manual

The downhole brines which contain magnesium and sodium sulfates react withcalcium hydroxide (precipitated during cement hydration) to form magnesiumhydroxide, sodium hydroxide, and calcium sulfate. The formation of magnesiumhydroxide (brucite) causes expansion as mentioned earlier. The formation ofsodium hydroxide increases the porosity of the cement since it is more solublethan calcium hydroxide. The calcium sulfate reacts with aluminates (present inthe 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, theproduct is a large molecule that requires more pore space than the set cementcan provide, causing excessive expansion. The effect of all these reactions canbe uncontrolled expansion leading to loss of compressive strength and eventualcomplete deterioration of the set cement

Temperature influences the sulfate resistance of a hardened cement. From inves-tigation conducted at both low and high temperatures, it was concluded that sul-fate attack is most pronounced at temperatures between 80F to 120F. Attemperatures of 180F and above, the attack is negligible. This conclusion is sup-ported by observation of actual wells. Cement failures due to sulfate attack aremore common in shallow wells where temperatures are lower than 200F.

The API classifies cements as moderately sulfate resistant (MSR) and highly sul-fate resistant (HSR) on the basis of the tricalcium aluminate (C3A) content. AMSR cement contains 3-6 weight % C3A; and a HSR one 0-3 weight % C3A. APIHSR cements , are less susceptible to sulfate attack after setting, and should beused whenever downhole brines may exist which contain magnesium and sodiumsulfates. Sulfate attack can also be substantially reduced by the addition of poz-zolanic 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 ofmoisture, can destroy the structural integrity of set Portland cements. The reactioninvolves the formation of carbonic acid which attacks the alkaline constituents(Ca(OHfavouredcium carbonate into soluble calcium bicarbonate. This begins achain reaction. The dissolved calcium bicarbonate reacts with the alkaline constit-uents forming calcium carbonate and water. The water dissolves more calciumbicarbonate. The net result is a “leaching” of cementitious material from thecement matrix, increasing its porosity and permeability and decreasing its com-pressive strength. Downhole, this can result in a loss of casing corrosion protec-tion and a loss of zonal isolation.



Cement Manual

Carbon dioxide corrosion of Portland cements is thermodynamically favored, andtherefore, cannot be completely prevented as long as Portland cement is used.For economic reasons, the approach which has been generally adopted is to slowdown the rate of degradation of portend cement by a combination of the followingmeans:

• Addition of a pozzolanic material (fly ash) to the cement to reduce the alka-line 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 Cpoz -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 devel-oped by Schlumberger. The developers claim that the blend, when mixed at acement-to-water ratio of 2.3 to 1 or greater, provides 45% more resistance to theaction of CO2 leaching in cements than either neat class H cement or type F flyash/cement admixtures of equivalent slurry density.

Another system developed by Halliburton is claimed to produce significantly bettercorrosion resistance to CO2 than the previously used systems, particularly whenwells are subjected to acid treatments. This claim is based on field tests per-formed on samples installed in actual CO2 injection wells. This system calledFlexcem is significantly more expensive than conventional systems. The productuses a crosslinked latex as its primary constituent, to which a quick-settingnon-Portland cement (25% by weight of latex), and silica flour (125% by weight oflatex) are added to provide structural rigidity. Base systems are mixed at around 9lb/gal and have been weighted to around 12 lb/gal. The developers claim that theproperties of the system such as thickening time, compressive strength, etc., arerepeatable 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 lowviscosities, and this behavior should be repeatable for several cycles. Unfortu-nately thixotropic slurries that truly behave as described are hard to design. Theytend to gel fast, but may not gel and thin through several cycles as it may be desir-able in some applications. In addition, they in general have limited temperatureapplications and their 'thixotropic' properties can be negatively affected by severalcement additives, again limiting the applicability of these slurries.



Cement Manual

In the real world, under downhole conditions, the best that can be hoped for is forthe slurries to develop high levels of gel strength once pumping is stopped. Thetrue gel strength properties of these systems need to be measured, at downholeconditions of temperature and pressure, using devices such as the MACS or theretrofitted UCA.

The primary advantages of thixotropic slurries are:

• Improving fill-up by reducing loss of slurry into weak formation, vugs, cav-erns, 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 anAPI Class A, G, or H cement at concentrations of 8 to 15 percent by weight of thecement. Other more sophisticated formulations are also available from the servicecompanies. Many of the applications of thixotropic slurries are at low tempera-tures, but uses of the systems have been reported to temperatures as high as260F.

Deepwater Situations

We already reviewed under Special Considerations, the complicating factorsassociated with cementing operations in deepwater locations. Here we will reviewslurry design considerations for this type of application. The main emphasis ascan be expected is on the slurries used to cement the shallow casing strings, par-ticularly if the potential for shallow water flows exist. Once these strings are suc-cessfully cemented, design of the slurries for cementing of the deeper casings canbe handled similarly as for land operations.

The following are the requirements for cement slurries to be used to cement theshallow (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 Manual

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

• 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 haveover 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 acrosshole intervals that present potential for fluid migration after the job:

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

Note: Transition time cannot be obtained from the consistometer thickening timecurve. Transition time needs to be measured using an apparatus like theMACS or the retrofitted UCA, under static conditions, and at downhole tempera-tures and pressures. It is normally accepted that if gas can be prevented frominvading the cement during the transition period, the chances of severe gasmigration problems in the well can be substantially reduced. Short transitiontimes are desirable. As a rule of thumb, less than ½ hr. transition time is consid-ered a short transition time.

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



Cement Manual

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

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

5. Laboratory testing. The gas migration control properties of the cement slurryshould be tested in the laboratory under simulated downhole conditions. An indus-try available procedure called the Scale-Down will be discussed below. The use ofthe Halliburton “flow potential” concept represents a good effort in the right direc-tion and should be used as a “screening tool,” but exclusive use of this and otherselection criteria fall short of the necessity of actually testing in the laboratory, theselected recipes under simulated downhole conditions before the final selection ismade. In cases where gas invasion/migration is a serious concern, testing acement formulation for gas migration control in the laboratory should be consid-ered as important as testing the thickening time and compressive strength of therecipe.

Scale-Down Laboratory Test Method

A detailed description of the Scale-Down method is outside the scope of this man-ual. 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 “worstcase” scenario. The method assumes that the offending gas zone (source of theinvading gas) has enough permeability, thickness and gas volume to fully invadeand pressure-charge the cemented annulus (cement column), if conditions allowit. In the laboratory procedure, the measured, actual gel strength development ofthe slurry is used to estimate the maximum potential pressure decline in thecement column. The calculated pressure decline schedule is then used to allowdehydration from the cement into the simulated gas formation, and to predictwhen a pressure differential needs to be applied across the slurry to potentiallydrive gas/water through the sample. The magnitude of the pressure differentialplaced across the cement specimen is calculated using Darcy's Law, assumingthat equal “bulk permeabilities” exist in the well and in the test cell. The gas influxinto the cement is measured .



Cement Manual

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

Figure 19: Scale Down Test Device



Cement Manual

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 labtesting

Introduction

A knowledge of sampling and blending techniques and quality assurance issueswith cements is vital to avoiding serious cementing problems. These techniquesare needed to ensure that the cement slurries pumped down-hole closely matchthe cement slurries as designed in the laboratory.

In many on-shore areas of the world, dry blending of the cement with dry additivesis the method of choice. Most off-shore operations will use liquid additives andneat cement. However, even off-shore, there is often a blend of cement used atsome stage of the well, e.g. Class G +35% silica.

The methods described here are the result of many years of accumulated industryexperience.

Sampling of materials to Use for Pilot Testing

The absolute necessity of conducting all the slurry design testing using the exactmaterials (cement, additives, field water) to be used in the actual cement job can-not be overemphasized. In order to have representative samples of the cementand additives to be pumped downhole, good sampling techniques need to beused.

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 issecured at the well location. If the water is in a tank at the rig, the sample needsto be taken from a valve, after flushing enough water from the line to make surethe sample is representative of the water in the tank. However, if there are settledparticles 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 thewater to try to collect the sample from the center of the tank.


Cement Sampling, Blending and Quality Control 3-63 Rev. 01/2002

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The additive lots to be used need to be put aside for the job. Under no circum-stances should several lots of an additive be mixed for the job. The same consid-eration applies for cement manufacturing runs. Samples of the additives for labtesting need to be taken from the lots to be used, from un-opened, undamagedbags. 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 samplingdevices shown below. Lines need to be purged long enough before taking thecement sample to make sure the sample is representative of the cement in thetank and not just what is trapped in the line. If the cement is in a transportequipped with an upper hatch, samples can be taken using a special tube (auger)that allows small samples to be taken simultaneously, at different depths, whenpushed into the cement from the top. The same techniques and devices can beused to sample cement blends from tanks and silos.

Pilot testing by the lab will establish a suitable slurry design on which dry blendingwill proceed. Once blended, the cement blend will have to be confirmed by repeat-ing the lab tests and assessing any variation.

Cement is a very reactive material and will chemically react with moisture in theair. This will change physical properties like thickening time and compressivestrength development. The extent to which this happens can vary widely. Somecements are particularly sensitive, others not so. In any case, small quantities,e.g. a cement sample, are particularly vulnerable to exposure and, if not ade-quately protected, exposure of just a few hours can make several hours differenceto the thickening time – generally lengthening it…. the consequences of testingsuch a samples and designing the retarder concentration can be disastrous! Thefollowing 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, cementtype 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


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- Labeled to show location, date, source (LAS, bags, etc), additivename, lot number, etc

Note: roll drums, or circulate LAS, to ensure active components of liquid additives arein 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 usesoft drink bottles.

Figure 20: Bulk Sampling Devices



Cement Manual

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 witnessthe 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 of the cement and additives

Step 7. Sampling 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 ofthe job size (slurry volume) should be made. Dry, liquid additives and cement insufficient quantities to cover contingencies such as greater than anticipated holeenlargement, etc, should then be secured in a clearly identified area. The materi-als 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 condi-tion of access roads (or marine transportation) is needed. This initial part of theplanning meeting may include a review of a diagram of the well location showingthe position of all the major components.

Selection of the Equipment

The next item of discussion is the selection of the equipment to be used (trans-ports, batch-mixer, pumps, etc.). To be able to make a good selection, it is neces-sary to know the capacity and capability of the transports, the batch-mixers andpumping equipment. This information affects how the blends will be transportedto location, stored while waiting for the job, and finally mixed and pumped. When-ever possible, critical liner slurries should be batch-mixed.



Cement Manual

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. Forexample, does the bulk plant have a scale tank and a blending tank, or is itequipped with only a scale tank? This is very important because the blendingpractice that consists of loading the cement and additives into the scale tank andpercolating air through the blend does not completely blend the cement andshould not be used alone. This practice is particularly ineffective when materialslike sand, hematite, salt and silica flour are part of the cement formulation. Airpercolating may actually de-blend the mixture, with the heavy and the larger parti-cles ending up at the bottom of the batch.

To properly blend cement, the blend must be pneumatically transferred a mini-mum of three times before it leaves the service company yard. So, if the plant isequipped with only the scale tank, it may be necessary to hook up a clean trans-port to the bulk plant, to use it as a blend tank. Often the use of a transport as ablend tank considerably extends the length of time that it takes to blend, due tothe difficulty of moving the cement blend from the transport back into the scaletank while blending the cement recipe. This must be done, particularly for criticaljobs. Percolation of air through the blend should only be used as part of theblending operation, and with some bulk plant configurations can be substituted forone 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 tankto the blend tank, from the blend tank to the scale tank, from the scale tankback to the blend tank, and from there to the bulk transport. Notice that thetransfer to the bulk transport is counted as a transfer. Experiments haveshown that this number of transfers generates a good blend. Some in theindustry prefer moving the cement six times.

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

3) Equivalent to three pneumatic transfers: The cement is percolated with air for10 to 15 minutes in the scale tank. From there it is transferred to the blendtank, and then to the transport. If this procedure is used, the percolating pres-sure should not exceed 10-15 psig in order to minimize gravity segregationwithin the blend. Notice that the percolation is counted as one transfer.



Cement Manual

4) Some locations throughout the world like to move the blend only twice before itleaves the yard, and count on the last transfer on location, from the transportto the batch or recirculating mixer to complete the blending operation. Thispractice is not recommended. The cement blends should leave the servicecompany location fully blended. In addition, if this practice is used, the opera-tions of sampling of the blend and confirmation testing will be negativelyaffected. Sampling and confirmation testing will be discussed later on in thissection.

Blend Size

The blending of the decided amount of cement formulation is done in "batches" atthe bulk plant. The selection of the size of the batches is affected by the capacityof both, the scale tank and the blending tank. It has been found that the if thetanks are over-filled, then the effectiveness of the blending operation is negativelyaffected. To properly blend the cement recipe, the bulk volume of each batchshould not exceed about 40% of the capacity of the smaller of the scale and theblend tanks. This is to allow plenty of empty space in the tanks for the cementblend to move freely and blend as it is being transferred from tank to tank. Ifneeded, the batch size can be increased to up to 50% of the capacity of the small-est of the tanks, but this is not a good practice if the blend contains large particleadditives such as silica sand, calcium chloride, hematite, salt, etc. When largeparticle materials are present, the 40% number mentioned above is the recom-mended batch size.



Cement Manual

Dry Blending Calculations

Important Note: It is a good practice to make sure that all the calculations neededfor the proper design of a blending operation be performed by two persons, inde-pendently 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 compo-nents of the recipe. This yield is determined from a material balance using thebulk densities and the concentration of the dry additives being used. The dry bulkyield of the given cement recipe is needed in order to properly size the batch to beblended. An example of these calculations is given below.

Figure 22: Dry Bulk Yield of a Cement Formulation

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

For the example case given in the Table, the calculated dry bulk yield of the partic-ular 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 batcheswhich will be required are determined, based as indicated before, on the need tostay at 40% of the capacity of the smallest of the scale and blend tanks. If forexample the capacity of the smallest tank was 280 cu.ft., then the maximum batchsize would be 112 cu.ft., and seven batches would be required to blend the 450sacks of the cement recipe.

Following, the weight of the cement and additives to be used in each batch aredetermined based on the concentrations of the recipe and the pre-selected size ofthe batch. A blending schedule is prepared. In the schedule, half of the cement isadded first, followed by all the additives which are then "sandwiched" by the sec-ond half of the cement. This sandwiching approach has been proven effective innumerous blending applications. Some in the industry like to use several layers:cement, additives, cement, etc. This is time consuming and, in general, does notgenerate better results than the single layer approach.

MaterialConcentration

(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



Cement Manual

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 drycement blend, to mix the cement slurry.

When liquid additives are to be blended into the mix-water (batch approach), theamount of mix-liquid to be used for each batch (tank) of slurry is calculated usingthe mix-liquid requirements of the given slurry. As an example, let's assume thatthe usable capacity of each batch-mixer tank is 45 bbls, the slurry yield is 1.63cu.ft./sk, and that the mix-liquid requirement for the slurry is 5.90 gal/sk. Let'salso assume that four batches of slurry are going to be mixed in each of fourbatch-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 themix-liquid required for each blend is 15.80 bbls ((112.5 sk x 5.90 gal/sk)/42). Thevolume 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 eachliquid 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

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 inspectthe equipment to be used. The main reason for this is to ensure that the equip-ment is functional and free of materials (old cement blends, etc) that could con-taminate. Once inspected, this equipment must not be used in other jobs untilafter the blending at hand is performed.

MaterialConcentration

(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



Cement Manual

Transports hatches must be opened and the inside of each tank inspected tomake sure it is completely clean. Clean equipment, free of possible contami-nants, 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 followingquality controlled blending procedures like the ones discussed here often takeslonger than other less rigorous methods. However, the methods suggestedshould produce quality blends closely matching the slurry formulations designedin 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 theassistance of the bulk plant operator will help in understanding of the equipmentlayout. It is important to question when any load devices were last inspected andcalibrated.

At this poin verify that the additives to be used in the blending operation have thesame lot numbers that were used to run the pilot tests. This is a critical point dur-ing the bulk plant inspection. It might not be possible to confirm the lot numbersof bulk materials such as hematite, silica sand, etc, but many of the critical addi-tives such as retarders, fluid loss additives, etc. have lot numbers stamped on thebags. If the additives are not of the same lot numbers, the blending operationshould not start until a repeat of the pilot testing is done with the actual materialsto 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 thelines (from the bulk storage tanks and exiting the scale and blend tanks and thehopper) be completely clean of potentially contaminating materials. In the sameway, the "socks" (dust collectors) often installed on top of the scale tank need tobe free from all material possibly accumulated in them from previous jobs. Thecleaning procedure needs to be performed prior to commencing the blendingoperation and it is carried out as follows:

All the lines are purged into the scale and blend tanks several times. The socksare then shaken for several minutes to allow discharge of materials into the scaleand 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 thereis only dust coming out of the discharge lines of the scale and blend tanks.



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With very dirty bulk plants (sometimes found in more remote locations of theworld), 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 helpscrub the walls. After the sand, the cleaning operation outlined above needs to berepeated from the first step. Some scale and blend tanks are equipped withhatches 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 opera-tion.

Some plants have socks on top of the scale and the blend tanks. Others onlyhave one set of socks. In any case, sometimes the socks are found to benon-operational. Every effort must be made to fix these devices before the startof the blending operation. Socks are used as dust collectors, but they are alsovery useful in putting back into the blend, the fine particles that tend to be carriedout by the air during the blending operation. Non-operating socks prevent theoperator from restoring the fine particles back into the blend, by periodically"shaking the socks" while blending. At the end of the cleaning operation, the bulkplant (scale, and blend tanks, hopper and all the lines) must be completely emptyof materials from previous operations.

Blending Equipment Calibration

As previously indicated, it is important to note the last time the scales were cali-brated 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 beout of calibration and need to be checked. The following "quick and dirty" test ofthe accuracy the scale tank can be run before a blending operation starts: afterzeroing the scale of the scale tank, two or three people of known weight climb onthe scale tank (on top or on the frame) and a weight reading is taken on the scaletank. The weight recorded on the scale should be within 10 to 20 pounds of thesum of the weights of the individuals on the tank. If safety considerations, ordoubt about the weight of the individuals, prohibit this ”quick and dirty" calibrationapproach, 5 to 10 bags of silica sand or barite on top of the tank can be used forthe same purpose. Again, the reading of the scale should be within 10 to 20pounds of the actual weight. If an error greater than 20 pounds is measured, theamount of weight in the tank should be varied (above and below the originalweight used), and the scale read again. This should allow a determination if theerror is constant or if it varies with changing weights. This procedure should berepeated several times, looking to see if a reliable, consistent and repeatable cali-bration trend line can be developed. If a calibration line cannot be developed forthe scale tank, the blending operation should be suspended until the problem isfixed by the service company.

Similarly, the additives scale needs to be checked using a known weight. Severalsacks of additives of "known" weight (one bag at the time) can be used to check



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this scale, or any other available material of known weight can be used. The addi-tives scale must be within a 1/4 of a pound or less of the known weight. It is rec-ommended that the additives scale be calibrated before the scale tank. By doingthis, the additives scale can be used to weigh the individuals or sacks of additivesto 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 correctzeroing of the scale tank. Zeroing means exactly that. It means to force the scaletank to read "zero weight" at the start of a blending operation. The bulk plantoperator makes the scale tank read "zero" by turning a knob on a beam typescale, or by pressing the zeroing button on an electronic read-out scale. Once thescale 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 ofconditions present when the scale was originally zeroed must be repeated or theweight 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 completelyfree of materials. When the tank is zeroed or when a weight reading is takingduring the blending operation, the goal is to read the weight of the materials inthe tank. So, the lines must be free of materials for two reasons. The first oneis that if material is left in the lines, the weight of this extra material is not fullyrecorded when a weight reading is made. This material left in the lines willthen be pushed into the tank the next time the line is pressurized. This caneasily add several hundred extra pounds of the material present in the lines tothe scale tank. The second reason is that lines full of material, because of theway they are connected to the scale tank, can add an undetermined amount ofstress to the tank, causing the load cell on the tank to record a certain (unde-termined) 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 levelor under atmospheric conditions (no pressure or vacuum). Some operators, tohelp facilitate the blending operation, prefer to zero the scale tank and makeweight readings either under vacuum or with pressure in the tank. This has todo 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 vac-uum), the operator might prefer to read how much material is in the scale withvacuum in the tank. On the other hand, when transferring material out of thetank, it might be easier to read the weight in the tank with pressure (say 30psig) in the tank. Either method is acceptable but again, once the scale iszeroed under a given set of conditions (vacuum or pressure), the sameamount of vacuum or pressure needs to be present in the tank when a weightreading 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 atatmospheric conditions (with no vacuum or pressure in the tank). This is the mostaccurate and trouble-free way to know the weight of materials in the tank. Thismethod should be the one used, unless the particular plant design prohibits itsapplication. Some plant operators resist this method due to the extra timerequired to bleed the pressure or release the vacuum from the tank before takingeach weight reading.

Proper zeroing and weight reading of the scale tank is so critical to the blendingoperation that its importance cannot be overemphasized. For example: If thescale tank has been zeroed at atmospheric conditions, and a weight reading istaken either under vacuum or with pressure in the tank, the weight read can beseveral hundred pounds below or above the true weight in the tank, dependingamong 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 ofthe air compressor to reduce the chance of moisture contacting the blend. This isparticularly 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 theblending operation.

Important note: Even after draining the moisture from the system, highly hygro-scopic additives may tend to absorb water from the air and therefore cause prob-lems 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 highlyhygroscopic materials (e.g. calcium chloride), particularly in areas of high humidity(for example Trinidad), to the mix-water whenever possible. Highly hygroscopicmaterials dissolve rather easily and in this way, it is ensured that the material willbe present in the slurry formulation when pumped downhole. It is recommendedthat this procedure (adding the material to the mix-water) be used also during thepilot testing of the slurry.

During blending, approximately 10 inches of vacuum are used to "pull" materialinto the scale tank. The storage tanks holding the bulk materials generally can bepressurized to help in transferring materials to the scale tank. The general proce-dure is to introduce first into the scale tank, half of the required cement. This isfollowed by other "bulk" additives such as silica flour and hematite. Next, the"sacked" additives are introduced through the additives hopper. This is then fol-lowed by the rest of the needed cement. Each time the operator needs to striveto get a weight on the scale tank, that is as close as possible to the cumulativeweight target. The "socks" must be shaken regularly during the blending opera-tion to minimize accumulation of materials in them.

The maximum acceptable deviation between the actual cumulative weight read onthe scale tank and the target weight should be about 50 lbs. It is industry experi-



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ence that trained operators, when required, can stay within this window. Onecommon reason that causes many operators not to be able to accurately transfermaterials into the scale tank, is not properly accounting for the material in the linesbetween either the bulk storage tank or additives hopper and the scale tank. Anestimate of the weight of material which the lines will hold must be made beforecommencing blending (the bulk plant operator normally has a good "feel" for thisweight). This will allow the operator to "fine tune" his operation so that a weight asclose as possible to the target value is obtained for the material being introducedinto the tank. Since the lines are full of material while transferring into the scaletank, the operator needs to aim for less than the target weight by the estimatedweight of material in the lines. He must then shut off the valve feeding materialfrom the bulk storage tank into the line, and purge the material in the lines into thescale tank. This purging of the lines may have to be repeated if it is suspectedthat material remained in "dead" spots of the lines. This can occur between shut-off valves and line sections which are not in the direct path of flow. After ensuringthat all of the material has been introduced into the scale tank, the reading of theweight 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 materialsintroduced into the blend. It should be noted that density differences betweenmaterials can significantly alter the weight of material in the lines. The operatormust therefore not assume that the same "adjustment" can be made for the differ-ent materials being blended.

If during a given transfer operation the operator does not bring into the scale tankenough of a given additive, causing the scale tank to read more than 50 lbs belowthe target weight, he needs to bring more additive into the scale tank. If on theother hand, he transfers too much of a given additive (more than 50 lbs over thetarget cumulative weight), proportional additions of the other additives and cementmay need to be made at the end of the transfer operation to keep the correct pro-portion of components in the blend.

Another common area where errors are made in dry blending is in not accountingfor 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 shouldalso be weighted to determine the rest of additive that is needed. Sacks usuallyweigh 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 thesack. Small amounts of additive must be weighted into a clean container, and theweight of the bucket itself must be accounted for.

When introducing additives through the hopper, the sacks must be carefullyinspected to ensure that no "rocks" of material are present and that the materialshave not absorbed moisture or have otherwise become contaminated. If anydoubt exists, the particular bag of material should not be used. Large "chunks" of



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additives might not break during blending. If small "lumps" are observed in thematerial being introduced into the hopper, these must be " broken-up" beforebeing included in the blend. Some service company locations use a screen overthe 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 inthe tank should be increased to around 30 psig to perform the first transfer. Ifextremely light additives are being used to blend "light-weight" cements, for exam-ple ceramic "bubbles", the transfer pressure should be reduced to about 6-8 psigin order to minimize blend segregation and large losses of these light additivesthrough the vents. In many cases this pressure is sufficient to transfer theselight-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 thelight additives back into the blend. After each transfer process, the scale tankmust be "pressured-up" and "blown-down" several times to maximize the amountof material transferred. It is normal to end up with 50 to 100 lbs of weight in thescale tank, even after several "blow- downs". This is likely caused by material thatremains 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 transferredto the "transport". After the final transfer has been made from the scale tank, afterseveral "blow-downs", and after the pressure in the tank has been bled down toatmospheric, 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 nextbatch of blended materials.

During the actual blending process, the "target" and actual cumulative weightsshould be documented and compared after each addition of additive or cement tothe blend. This information is very important not only in "keeping track" of theweights added but also in ensuring quality control at each stage of the operation.The "target" cumulative weight for any particular additive is determined by addingthe theoretical weight of the additive to the actual cumulative weight present in thescale tank (recorded after introducing the previous additive to the blend). Sincescale tanks normally can only read weight in increments of ten (10) pounds, targetcumulative weights are rounded off to the nearest multiple of 10 lbs.

As mentioned before, The maximum acceptable deviation between the target andthe actual cumulative weight after each addition of bulk material to the blend isaround 50 lbs. If the actual cumulative weight exceeds the target value by morethan 50 lbs, proportional adjustments need to be made to the weights of the addi-tives and cement to compensate for the excess. Extra amounts of materials aregenerally added on top of the second half of the cement. It should be mentionedhere that small differences in the concentration of critical additives (retarders, fluid



Cement Manual

loss, dispersants, etc.) can significantly alter the final properties of the blendedproduct.

While transferring the blend to the "transport" for delivery to the rig site, a samplemust be taken for performing confirmation tests on the blend. Sampling proce-dures are discussed in more detail later (see Sampling).

Important note: When extremely light additives (e.g. ceramic bubbles) have beenblended in the cement, re-blending on location may need to be done to ensure thehomogeneity of the blend. This is particularly critical offshore. Extremely lightadditives tend to "gravity segregate" during transport to the rig, and while beingblown to the rig tanks from the boat on offshore jobs. A clean, empty tank of ade-quate capacity should be used on location to transfer the blend at least twice tore-blend it. Samples of the reblended material should be taken after the re-blend-ing 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 todry-blending of additives for spacers.

Liquid Blending When Using Batch-Mixers

After determining the total volume of mix-liquid to be blended and the minimummix-liquid to be blended in each batch-mixer tank (when batch-mixing is used), anexcess mix-liquid to be blended must be decided upon. This excess mix-liquid isneeded to allow for extra volume required to fill lines and prime pumps, etc. Inaddition, some extra volume is needed to be able to effectively "fine tune" theslurry density during batch-mixing at the rig-site. The procedure normally used onlocation is to mix the slurry 0.2 to 0.5 ppg heavier than planned by transferringsome 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 stirringand making measurements with a calibrated pressurized mud balance, until thetarget slurry density is obtained.

Prior to commencing the liquid blending operations, all blending equipment musthave been cleaned and inspected. The first critical operation in liquid blending isensuring that

the correct amount of water is added to the blender (batch-mixer tank). Thesource of the water must be checked to make sure is the same as was used dur-ing the laboratory testing. Batch-mixer tanks normally have barrel markers (vol-ume indicators) to be able to tell how much volume of liquid is in the tank. Thesemarkers 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 thetank. One good method is to use a clean pump truck and to pump the water intothe batch-mixer tanks from the truck's displacement tanks. The pump truck must



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be well leveled, and all the lines, valves and connecting hoses to the batch-mixermust 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 accordancewith the blend size design, the correct volumes of liquid additives are then intro-duced directly into the tank.

Important note: liquid additives often need to be added to the mix-water in apre-determinated order to maximize their effectiveness and to avoid some incom-patibility problems. This order of addition must be followed during the liquidblending operation. This sequence should be the same that was used in perform-ing the pilot tests.

Liquid additives often come in 55 gal drums or 5 gal pails. It is important to makesure that all the containers are full (have not been partially emptied). Often it isassumed that a 5-gallon pail or a 55-gallon drum actually contain those volumesof liquid additives. This practice can potentially result in blends that do not containthe correct proportion of additives. A good way is to used a graduated containerlike a 5 gal bucket. The graduated pail can be used to check the volumes con-tained in the "5-gallon" pails. If measurements on several randomly selected5-gallon pails indicate that they indeed contain 5 gallons of liquid, the contents ofthe pails can then be added directly into the mix hopper. Again the graduatedbucket can be used to spot-check the volume in the 55 gal drums. This is nor-mally done at the service company yard. One drum can be emptied using thebucket, and the volume checked. If it checks fine, the thing that needs to be donenext 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 mustbe stirred for a minimum of 15 minutes to ensure that a homogenous mixture isobtained. A sample must then be taken for performing confirmation tests on theblend. 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 liquidadditives to the mix water. This technique is most often used in off-shore loca-tions. Liquid additives may be dumped from gauge tanks into the mixwater tanksor more sophisticated computerized injection devices may be used. One impor-tant issue with this type of cement slurry mixing is the maintenance of the correctslurry density. Thus, calibration of the equipment and proper coordination of den-sity measurement with the rate of addition of cement, mixing water and liquidadditives 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 prob-lems with dispensing systems and maintaining good control of slurry density. Ide-ally, the density of cement slurries needs to be controlled within +/-0.1 lb/gal.



Cement Manual

This is not always achieved even with the latest computerized equipment. Belowis 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 100bbls were mixed in a batch-mixer at the desired density of 15.8 lb/gal. The slurryin the batch-mixer was stirred in the tank while the first 70 bbls were pumpeddownhole. As seen in the figure, the density of the initial 70 bbls varied from 15.1to 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 liquidadditives:

• 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 con-stant delivery of liquid additive.

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

• The dispersion of liquid additives throughout the mix water should be veri-fied.

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

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

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

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

• The cement, additives, and mix water used for design and testing shouldalways 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 sincethe samples are used to run confirmation tests on the blend. The success of theblending operation is measured by how well properly taken samples of the blendcompare 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 samplingdevices such as Halliburton's Accu-sample Dry Bulk material collector. Compara-ble devices are available from the other service companies. Many service com-pany locations are equipped with these types of collectors. The devices enablesamples of the blend to be automatically taken from the "stream" while the blendis being blown to the "transport".



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The sampling frequency of the "stream" can be adjusted from once every fourseconds to one sample every 1.5 minutes. If needed, two different sample ratescan be pre-selected and the two rates can be used at will during the samplingprocess. The following are "ball park" sample settings for the device for differentblend sizes:

Figure 25: Example of Sample Taking for Typical Automatic Samplers

For blends containing only fine materials such as cement, retarders, etc., the col-lector is assembled with four collecting holes (0.234 in. dia.) spaced across thewidth of the discharge pipe. For blends containing granular materials like silicasand, lost circulation materials, etc, a single hole (0.375 in. dia.) is used to collectthe samples from the center of the stream. It should be noted that if the singlehole arrangement is not available for sampling the coarser blends, plugging mightoccur if the four-hole arrangement is used. Under these conditions it will be betterto sample manually (see below). Prior to taking the sample, the device must beset at the desired sampling rate, and it must be checked to make sure that it isoperating 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 bevery effective. It consists of taking the sample by using a discharge valve locatedon the line going from the scale tank or the blend tank to the transport. Prior totaking 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 andclosing the valve, throughout the transfer of the batch to the transport (usuallysampling is started a few minutes after the start of the transfer operation, to makesure that the sample is representative of the current batch and it is not beingaffected by material left in the lines from the previous batch. A well taken sampleneeds to contain from 20 to 50 lbs of blended material.

Batch Size SksSample Rate

SecondsTotal Sample Collected

Gals

50 4 0.5

150 20 0.5

250 20 0.75



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Sampling Liquid Blends

When sampling liquid blends, a clean, unused container of at least one galloncapacity must be used. Prior to taking the sample, the blend must be agitated fora minimum of 15 minutes to ensure that a homogenous mixture is obtained. Thesample is usually taken from a valve on the bottom of the blender while the blendis being agitated. The sample must not be taken until the valve and line leading tothe valve have been purged. If the batch-mixer is not equipped with a samplingvalve, the sample can be taken from the top of the tank by using a container anddipping it low into the body of the liquid. After taking the sample, the containermust be tightly closed and labeled as mentioned before. A sample must be takenfrom each of the blend tanks.

Composite Sample Preparation

Each batch sample can be tested to check if the specific blend resembles theproperties measured during the pilot testing. However, this can be extremelyexpensive and time consuming, and is not normally done. When done, it is onlyfor small critical jobs (like squeezing or plug cementing). Normally what is doneis that the different batch samples are mixed into one or two composite samplesand the confirmation tests are run on the composite samples. This technique,when combined with the rigorous blending practices outlined in this section hasbeen very successful in numerous jobs throughout the industry worldwide.

One way to mix the different sample batches together is to place them in a cleandrum or container and roll the container until the samples are completely mixed.However, depending on the number of the samples, location, etc. this is notalways possible. What is often done is the following: each sample bag is thor-oughly mixed (a large metal spoon can be used for this purpose). Next, three tofour spoonfuls full of material are taken from each sample bag (or more if neededfor volume), and placed into a clean "composite" bag. As a rule of thumb, the vol-ume of the composite sample should be approximately equal to the average vol-ume of the individual sample bags. The "composite" bag must be thoroughlymixed as before. Then the bag must be tightly closed and labeled "compositeblend" 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 amountsfrom each container into a clean "composite" container. The "composite" con-tainer must be closed and thoroughly mixed as before. Then the container mustbe labeled "composite blend" and with the other important well information.

All the samples dry and liquid, from each batch and the composite ones, must besaved in a dry environment (often in the laboratory) for future verification orpost-analysis work. The sampling procedures discussed above should also beapplied to the preparation of composite samples of dry and liquid blends of spac-ers.



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Confirmation Testing

The "composite" samples are used by the lab personnel to run the confirmationtests on the blends. To run the confirmation tests, the dry and liquid blends arecombined in the same ratios as used in the pilot tests. The confirmation testsmust be run using the same industry proven testing procedures that were usedwhen running the pilot tests.

First, the slurry density should be verified with a calibrated pressurized mud bal-ance and then a thickening test should be run. Simultaneously, settling testsshould be run. Next, free water, fluid loss, rheology, spacer compatibility andfinally compressive strength tests are run. Following are some guidelines for toler-ances to help decide the acceptability or rejection of the blended cement formula-tions.

Slurry Density

The pressurized mud balance density of the slurry needs to be within 0.1 ppg ofthe target density (as designed during the pilot testing). The same for the densityof the blended spacer.

Thickening Time

The thickening time must not be less than the minimum required thickening timefor the job. The minimum required thickening time for the job is computed as theestimated job placement time plus at least one (1) hour safety factor to account forunplanned events. Any preconditioning time which was used in the pilot test (tosimulate 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 estimatedjob placement time. However, thickening times that run long may be consideredacceptable 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 thesettling test.

Free Fluid

The free fluid must be essentially the same as the one obtained during the pilottests. For slurries designed to prevent gas migration, the free water needs to bezero (0) ml.



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Fluid Loss

The API fluid loss must be within about 10 ml of the pilot test result, with slurriesdesigned to have "good" fluid loss properties. Larger variations can be acceptedwith slurries designed with higher fluid loss values (see important note below).

Rheology

The consistency of the "composite" blend should allow surface mixing of the slurrywithout difficulty. In addition, the rheological properties of the "composite" fieldblend should produce similar pressure drop losses as those predicted from thepilot testing.

Spacer Compatibility

The "composite" cement blend and spacer system must exhibit similar compatibil-ity characteristics as observed during pilot testing.

Compressive Strengths

Compressive strength is perhaps the most difficult test to reproduce even duringpilot testing. As a guideline, WOC times (particularly at liner tops) should be rea-sonably close to the WOC times determined during pilot testing. In addition, thecompressive strengths of the composite blend should be reasonable close to thevalues obtained during pilot testing.

Important Note

All of the confirmation test results must be considered in assessing the quality ofthe blend. Some results may be more critical in a particular case, and this mustinfluence the decision as to use or reject the blend.



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Cement Manual

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 replacedwith cement slurry. The slurry, when set, will support and protect the pipe andprovide zonal isolation during the life of the well. In most cases the result is lessthan ideal.

Displacement efficiency is measure as the percentage of mud removed from thesection of annulus to be cemented. Most experts agree that the best that can beexpected, in a very well conducted cementing operation, is to displace andreplace with cement slurry, about 95% of the mud in the annulus. In the best ofthe cases, 5% of mud is left in the annulus and that mud is capable of causingproblems 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 to6.3 bbls of mud (5% of 126 bbls). If, after the cement job, this mud remains inlong channels within the bulk of the cement, and/or against the casing or the per-meability, then there is a good chance that problems may develop in the life of thewell (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 smallpockets or short channels that do not contact the pipe or communicate betweenzones, then serious problems will not be observed.


Displacements 4-1 Rev. 01/2002

Cement Manual

To be able to remove as much as possible of the mud in the annulus, the industryhas developed a variety of methods and techniques. Some of them are purelymechanical such as pipe movement (with or without scratchers), casing centraliz-ers, turbulators. Others depend on hydrodynamic effects such as fluid turbulence,fluid stress at the formation wall, filter cake erodibility. A frequent complicating fac-tor in the displacement process is that cement slurries and drilling fluids are chem-ically incompatible. When mixed, chemical components contained in the fluidformulations react with each other, generating undesirable viscosity increases andloss of fluid loss control. The formation of viscous fluid in the annulus can seri-ously jeopardize the displacement. Channeling of the cement slurry can bypassthe mud. To reduce the chance of cement slurry and drilling fluid contacting eachother, the industry has developed fluids known as spacers (and/or flushes) thatare chemically friendly with both cements and the muds. These fluids arepumped 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 waterbased. Oil based systems are formulated with a variety of 'oils', ranging from die-sel to more sophisticated, more environmentally friendly chemicals such asesters, LAO’s.

In general, cement slurries are not compatible with water base muds, but theytend to be even less friendly with oil based systems. Incompatibility problemsgenerally manifest themselves by viscosity increases (in some cases formingalmost solid masses). However, mixing can also degrade fluid loss control, freefluid and compressive strength.


Rev. 01/2002 Displacements 4-2

Cement Manual

The illustration of a cement slurry/water based mud incompatibility, is theputty-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 slurrysetting

However, there are significant advantages with OBM:

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

• they do not tend to build excessive gel strengths downhole. This alsohelps 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 areusually 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 theneed to integrate all aspects of the well planning.



Cement Manual

One aspect of the placement process that needs special attention with oil basemuds is the spacer design. In wells drilled with OBM, the surfaces are normallyleft oil-wet. Since cements do not bond to oil-wet surfaces, every attempt needsto be made to render the surfaces water-wet before they are contacted by thecement slurry. (In fact, cements do not bond well to water-wet surfaces either butthere is better adhesion). Spacer fluids used with oil base muds must contain sur-factants capable of water wetting the surfaces. Many spacers and flushes areavailable from the service companies. Since every well situation is different, it isnot possible to make "blanket" statements as to which systems are the best. Fieldsuccesses, or failures, should always be analyzed to assist in determining thedegree of effectiveness of a given system. The make-up and chemistry of the mudsystem will influence the choice of surfactants so it is important to use samples ofthe actual mud.

An example of laboratory data collected showing some viscosity incompatibilitybetween an oil based mud and a cement slurry is given below in Table IV-1. Com-pare, 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 %/%

TempF

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



Cement Manual

Rheological Properties

Rheological Models

Detailed procedures for rheological measurement are contained in the documentAPI RP-10B. In addition, methods and equations for the calculation of pressuredrops and flow regimes are given in the same document. Here we will only brieflyreview these topics.

To be able to characterize the flow behavior (friction pressures, flow regime) inany geometry (pipe, annulus), a rheological model that best represents the vis-cometry data must be selected. The data obtained using a rotational viscometeris converted to shear-rate and shear-stress data. A rheological model for the fluidis then selected by regression analysis or by plotting the shear-rate/shear-stressdata, and deciding on the model that best represents the data.

Rheological models describe the relationship between shear-stress andshear-rate of a fluid. The most commonly used models of drilling fluids, spacersystems and cement slurries are the Bingham plastic and the Power Law models.However, three parameter models are being used more and more throughout theindustry.

Newtonian Fluid Model. When plotting shear-stress versus shear-rate on Carte-sian (rectangular) coordinates, a fluid behaving as a Newtonian fluid will generatea straight line through the origin with a positive slope (Figure Curve A). This is amodel that often represents preflushes (un-weighted fluids) pumped ahead ofspacer fluids during cementing operations.

Bingham Plastic Model. When plotting shear-stress versus shear-rate on Carte-sian (rectangular) coordinates, a fluid behaving as a Bingham Plastic will generatea 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-stressat zero shear-rate (Figure Curves B and C).



Cement Manual

Figure 3: Rheological Models

Selecting a Rheological Model

The shear-stress, shear-rate data of the fluid should be analyzed against the dif-ferent rheological models. Often, regression analysis is performed. The modelwith the best fit is then selected. Once a model has been selected, the equationsdeveloped for that model are used to calculate, for example, the pressure drop forthe given fluid in a given geometry. Again, the equations for the different rheolog-ical models are contained in RP-10B. The calculations are normally performedusing computer simulators.

Factors Affecting Rheological Measurements

As seen, temperature can have a marked effect on the rheological properties ofcement slurries, spacer fluids and drilling muds. The rheology of the fluids shouldtherefore be measured at temperatures that are representative of the well condi-tions. If the BHCT of the well is less than 185F, the rheology is often measured ata temperature between the surface and the BHCT. If the BHCT is higher than185F, the rheology is then measured at 185F. This assumes that a HPHT rheom-eter is not available. In critical wells, however, an effort needs to me made tomeasure the rheologies of the fluids at realistic well temperatures using a HPHTrheometer.



Cement Manual

In a well, the temperature varies up and down the casing and the annulus. Strictlyspeaking, the rheology should be measured at several representative tempera-tures covering the range anticipated. Rheology measurements are affected bysedimentation tendencies, chemical reactions and other time and shear effects.Calculations using rheology data should be expected to contain a degree ofuncertainty and need to be handled accordingly.

Pressure does not affect the rheology of water base fluids (cement slurries andspacers) as much as temperature. However, for oil base muds, pressure – aswell 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 casingand cementing. Hole conditioning should be done before pulling out to runcasing and also once casing is on bottom. Hole conditioning, accom-plishes several goals:

• Mud rheological properties are lowered to reduce surge pressures andfacilitate mud displacement – removal of low gravity solids and chemicaltreatment

• 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 displace-ment and a successful cement job. Thus, one of the issues is how long to circu-late?

Traditionally, “rules of thumb” such as circulating bottoms-up twice or circulatingthe open hole volume have been used. Displacement studies have shown, notsurprisingly, that “rules of thumb” can be unreliable.

More quantitative method have been used such as the “tag” or “dye tracer” meth-ods. The technique involves adding a dye or other marker (e.g. a carbide slug) tothe drilling fluid and circulating the well at a constant pump rate. When the dye ormarker is detected in the return line, the percentage volume of mud circulatingcan be determined based on the well geometry and the open hole caliper log.



Cement Manual

The use of such tracers, however, is time consuming and subject to gross errorsin 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 isdifficult.

A possibly more reliable method continuously estimates the circulatable hole (thepercentage of open hole mud volume that is actually moving during conditioning).This provides knowledge of when circulation at a given rate is no longer providingadditional benefit. With this information, the circulation rate can be increasedand/or other techniques can be applied (pipe movement) to improve the percentof circulatable hole. A knowledge of how much openhole mud is circulating is ofparticular importance in highly deviated/horizontal holes, due to the potential pres-ence of solids beds on the low side of the hole.

The continuous monitoring technique uses a software package, and it is based onvery accurate measurements of wellhead pressure and flow rate of the drillingfluid while conditioning. The wellbore geometry, including an accurate caliper log,and the drilling fluid rheological properties must also be known to predict the per-centage of circulatable hole. The calculation is simply based on the pressure dropthat should occur in the openhole section of the annulus. If the hole has 100% ofthe drilling fluid circulating, a certain pressure drop for the openhole section canbe 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 annuluswill be higher.

The software used calculates the percentage of circulatable hole based on theactual hole size (caliper). An example of the use of this technology in an actualwell is shown in the following figure.

Again, as with the tracer approach, this technique is difficult to apply, time con-suming and subject to some error. However, just monitoring pressure against timefor a couple of flow rates can help establish whether mud is being brought into cir-culation or not.



Cement Manual

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 (cir-culating). The goal of the conditioning process is to end up with a “highly mobilemud” across the entire annular cross-section. If this is not done, the situationdepicted below may occur.

Figure 5: Cementing with Unconditioned Drilling Mud

10

8

6

4

2

0

100

80

60

40

20

00 30 60 90 120

Time (min)

Wel

lhea

d Pr

essu

re (1

00 p

si)

Flow

Rat

e (b

bl/m

in)

Pseu

do-D

ispl

acem

ent

Effic

ienc

y (%

)Efficiency

Rate

Pressure

Designates Pipe Movement

FILTRATE

FILTRATE CEMENT

CASING

LOWMOBILITY

MUD

FILTERCAKE

MOBILEMUD

FORMATION



Cement Manual

Several investigators have conducted research on hole conditioning, mud proper-ties and displacement.

Example, ideal drilling fluid properties to be achieved before cementing a verticalwell 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 lowside of the hole (barite settling known as sag). If solids settling from the mud isnot prevented, a solids channel can form. These solids channels are very difficultto remove. Also, barite sag can lead to loss of well control due to the resultingeffective reduction in mud density (hydrostatic head). To achieve the propertiesgiven 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 valuesgiven in the tables, the properties downhole may not have the desired values dueto 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 pro-gressive gel)

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

Deviation Angle, ° Yield Point at 72°F, (lb/100 ft2)

45 15

60 20

85 28

90 30



Cement Manual

To adjust drilling fluid properties prior to cementing, the muds may be treated withadditives (dispersants, etc.) in the mud pits prior to circulation and/or during circu-lation (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. Athick mud filtercake is not desirable because it is hard to remove, does not bond tocement and can lead to poor long-term zone isolation. To minimize soft thick filter-cake a low fluid loss is needed. Mud cake can easily be checked by the mud engi-neer and the thickness will be reported on the Mud Reports.

Gel strength development is another property that should be checked andadjusted as needed. Muds with 'flat' get strength profiles - those that do notincrease much with time - are desirable. WBM’s in poor condition need to beavoided.

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 densityof the fluid being displaced

• The viscosity of the fluid doing the displacing needs to be higher that therheology of the fluid being displaced.

In cases where the pore/frac window precludes density differences then a rheol-ogy hierarchy should be used to minimize channeling.

An improved technique over conventional concepts of density and rheology hier-archies 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 atthe 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 chan-neling 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 den-sity of the fluids) needs to be adjusted for the given annular configuration andpump rates to be used. These calculations are normally performed using acement job simulator.



Cement Manual

The concept of pressure drop hierarchy explains why it is possible to effectivelydisplace a heavier fluid with a lower density one. If the lower density fluid has arheology 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 dis-place the heavier fluid with minimum tendency to channel. A good example ishole cleaning using high consistency foamed fluids.



Cement Manual

Erodibility Technology

Wellbore Condition

The outcome of a primary cementing operation is greatly influenced by the condi-tion of the wellbore at the time the cement slurry is pumped. The Figure showsthe condition in a wellbore across permeability, at the end of drilling with a poorWBM after running casing.

Figure 8: Typical Wellbore After a Shutdown Period

This figure shows dense filtercake next to the formation wall, covered by partiallydehydrated gelled (PDG) drilling mud and moderately gelled (MG) mud.

Moderately gelled mud has been defined as a portion of mud that has developedgel strength in the absence of shear during static periods. Partially dehydratedgelled mud is mud which, in addition to developing static gel strength, has alsolost 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 goodquality OBM the least likely. If a poor WBM is being run such that these propertiesoccur the best course of action would be to remove the mud company.


Erodibility Technology 4-13 Rev. 01/2002

Cement Manual

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 dehy-dration across the openhole permeability. Tests have shown that displacement ofthe MG mud is not the real problem during primary cement jobs. The real difficultyis the removal of the PDG mud from the wellbore. The Figures below illustratethis. They show PDG mud and filtercake trapped between the cement and thepermeable 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 investi-gate gelled mud displacement. This cell is called an "erodibility cell."


Rev. 01/2002 Erodibility Technology 4-14

Cement Manual

Figure 10: Diagram of Erodibility Cell



Cement Manual

Figure 11: Photo of Erodibility Cell

Definition of Erodibility

Erodibility has been defined such that high values would mean the given PDGmud would be easy to erode. On the other hand, low values would mean the PDGmud would be hard to remove (low erodibility). Thus, erodibility was defined asinversely 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 theflowing fluid and the PDG mud.

It was found that chemical attack is an extremely effective way to increase theremoval of PDG mud. It was shown that certain chemical treatments allow effec-tive removal in situations where shear stress at the wall alone could not be usedbecause of the high pump rates required. In other words, chemically it is possibleto cause the PDG muds (and filtercakes) to erode at substantially lower interfacialshear stresses.



Cement Manual

Caution needs to be exercised in so far as different mud systems are likely tobehave differently due to their chemical and physical make-up.

This again emphasises how important the mud properties are to the physical dis-placement process.

Erodibility “Rules of Thumb”

Experiments with the erodibility cell have suggested the following "rules ofthumb":

• 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 fairlyeasily.

• Erodibilities above 30 are very desirable (systems are quite easy toremove).

Example of Field Application of the Erodibility Technology

Some computer simulators are now able to make erodibility calculations. How-ever, to help understand the process, the following example goes through the pro-cess, 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 removethe PDG mud from the open hole in this well. As a first approach, it is planed touse 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. Productioncasing (5-1/2 in., 17 lb/ft) will be set at 13,000 ft in an essentially gauge hole of 8in. There is a 100 ft washout zone near the shoe of the 9-5/8 in. casing with anaverage hole diameter of 9.0 in. Fracture gradient at the bottom of the hole is 17lb/gal equivalent. The cement slurry to be used is a 16.0 lb/gal system with aFann rheology of 124, 84, 68, 51, 23, 13. It will be brought back 500 ft into theoverlap.

The mud density is 15 lb/gal. PV = 15 cp, YP = 10 lb/100 ft2. Using the erodibilitycell, its erodibility was determined to be 12.



Cement Manual

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 (holediameter 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 canbe 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 neededin the open hole to erode the PDG mud and filtercake.

The next step is to design spacer systems and to calculate their pressure drop perfoot of open hole configuration for this well to see if they are capable of developingthe 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 thecement slurry to be used, and when tested for settling, the spacers did not settlestatically or dynamically. All the spacers had a density of 15.5 lb/gal, and they allhad good fluid loss control. The table below gives the rheology of the spacer sys-tems.

Figure 12: Spacer Rheology

Using a computer program, the pressure drop for each of the three spacers wascalculated for this well's open hole configuration. The pressure drop for water wasalso calculated. The following table summarizes the results obtained:

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



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

Spacer 2


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

Spacer 3


BPM in. psi/ft

5 8 0.0549

5 9 0.0251

8 8 0.0728 *

8 9 0.0333

14 8 0.1027



Cement Manual

From the table above, spacer 1 would have to be pumped at 14 BPM, spacer 2 at12 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 greatchance that PDG mud will not be removed from the washout zone. This examplehelps explain why it is so hard to get good cement jobs in holes with large wash-outs.

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 spacerfluids. Certain spacers and flushes can increase the erodibility of PDG mud bychemical means.

ECD Calculations

Again a computer program was used, this time to see if the selected flow rates foreach 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 ofcalculations, it was assumed that 1,000 ft (in the annulus) of spacer would beused in the job.

Maximum ECDs at the Selected Rates

14 9 0.0466

Water


BPM in. psi/ft

12 8 0.0375

12 9 0.0120

14 8 0.0498

14 9 0.0160

Spacer Rate BPMMaximum ECD at the

Bottom lb/gal

1 14 16.4

2 12 16.3

3 8 16.1



Cement Manual

As can be seen from the table, the three spacers at their engineered rates wouldwork (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 andflow rate combination to use for the job would be determined using the erodibilitycell. Each spacer would need to be tested (pumped at the cell rate equivalent tothe field rate selected), over a PDG mud and cake bed deposited with the samemud, 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 betested at this stage.

Obviously, this is a very time consuming and labour intensive exercise which willalways be subject to the difficulty of having a mud sample truly representative ofthat in the well at section TD. The best that can be expected is to be able tobracket the likely properties of the type of mud in use. If it looks poor, replacementshould be considered.

The Phenomenon of Free-fall

In the great majority of primary cement jobs, the densities of the spacer fluid andcement slurry are greater than the density of the mud. Because of this density dif-ference, the well "goes on vacuum" or "U-tubes" while the heavier fluids are beingpumped down the casing.

Free-fall presents many problems in primary cementing. For example, while theheavy fluids (spacer, slurries) are free-falling, a vacuum is created at the well-head. 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 thespacer, the slurries and the mud in the hole. The phenomenon of free-fall is simi-lar, in principle, to the U tube manometer problem. In a U-tube manometer, withtwo different density fluids, there is a difference in the elevation of the two fluids atrest. If this equilibrium is changed, or disturbed in any way, the fluids will oscillateuntil the equilibrium position is again reached. In the case of free-fall during a pri-mary 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 cementslurry was pumped in a well to cause the well to "go on a vacuum" and then nomore slurry or drilling mud was pumped after that. In this situation, the fluidswould also free-fall seeking an equilibrium position. The real problem is muchmore complex since fluids are continuously being pumped at the surface, whilethe free-fall phenomenon is taking place. The "new" fluid being pumped at the



Cement Manual

surface eventually lands on top of the free-falling column and has an added directeffect on the free-fall phenomenon.

The frictional pressures generated by the flow of the fluids have a strong effect onthe free-fall phenomenon. Frictional forces resist and slow down the rate offree-fall of the fluids. At a given time during free-fall, the flow rate of the fluids isdictated by the difference in density of the fluids, by the length of the column ofeach fluid in the well, and by the frictional forces which in themselves are a func-tion of the free-fall rate. During free-fall, the fluids move at flow rates whichchange constantly and are not equal to the surface pumping rate. Initially, thefree-falling column of fluids moves faster than the surface pump rate. Eventuallythis rate reaches a maximum value and then slows down as the heavy fluids getclose to the bottom of the well or even "turn the corner," and the lighter displace-ment fluid is pumped behind them. During the deceleration stage of free-fall, thefluids in the well may move at rates below the desired minimum rate for the job.



Cement Manual

The early accelerationstages of free-fall causea "partially empty" or"discontinuous" zone toform in between thefree-falling column andthe wellhead. In thisdiscontinuous section ofthe well, the fluidsfree-fall at low pressures(even under vacuum)and do not fully fill theinner diameter of thepipe. The length of thisdiscontinuous zone con-stantly changes duringthe entire free-fallperiod. It is nonexistentat the onset of free-fall,reaches a maximumlength sometime duringfree-fall, and eventuallybecomes nonexistentagain at the end of free-fall.

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 abruptlyby "running into the plug" too fast. It is possible to create large pressure surges inthe well which can be detrimental, possibly causing damage to the casing or frac-turing 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 assum-



Cement Manual

ing that the surface pressure is essentially equal to zero while an "empty" gapexists in between the free-falling column of fluids and the wellhead.

The development of free-fall models has substantially improved the industry'sunderstanding of the phenomenon of free-fall. With the use of the mathematicalmodels, job designs can be performed for specific cases. Some general conclu-sions have been reached through the use of simulators:

• It is possible to estimate the free-fall rate of the fluid column at any time dur-ing 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 sur-face, 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 circu-lation 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 vac-uum 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-fall-ing 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 com-plete stop.

• Free-fall can be prevented by choking the annular returns



Cement Manual

Optimization of the Displacement Process

The transition from hole conditioning to spacer pumping to cement and mud dis-placement needs to be done with minimum shutdown time to minimize mud gelstrength 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 com-puter simulator must be used to optimize the centralizer program. Extendedreach and horizontal wells require careful planning and use of computer simula-tors.

Many different types of centralizers are available from the service companies.Some of them are designed for specific applications such as slim holes, andextended 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 onthe well conditions and configuration. Below are some general guidelines for theselection 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 flu-ids to swirl) are used in narrow annuli, but normally they do not provide as good astandoff as bow spring centralizers.

When the pipe is to be rotated, bow spring centralizers can be installed over stoprings (and in some cases over pipe collars if annular clearances allow). This facili-



Cement Manual

tates running in hole easily without hanging up (for pipe rotation, the pipe shouldbe free to turn inside the static centralizers). However, this type of installation isnot good if reciprocation is used because the pipe cannot be rotated.

Reciprocation requires the centralizers to be placed between collars, or betweenstop rings that are installed far enough apart to accommodate the reciprocationstroke without moving the centralizer. This installation, however, may cause thecentralizers to be subject to damage while being run in very tight or high angleholes. 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 havebeen found to produce the lowest holding forces.

For low deviation (say less than 20 - 30 degrees), bow spring centralizers are nor-mally 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. Positivestand-off centralizers (straight vanes, turbulators, etc.) are used when the bowand semi-rigid types are not adequate. In any case, it is very important to try tomaintain high levels of standoff (80+%) whenever possible. In some high angleholes, the 'turbulator' type centralizers have been found to “plow” their way intosoft 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 central-izers are often considered due to their potential higher standoff over the semi-rigidvane type. Double-bow centralizers generate less starting and running forcesthan typical bow centralizers, but better restoring forces than conventional bowspring centralizers under lateral forces. Some operators have used combinationsof rigid and semi-rigid centralizers in highly deviated and horizontal holes to helpenhance the chance of getting a good cement job. In all cases, standoff needs tobe calculated at the lowest point of casing sag, in between the centralizers.

Recently, roller blade type centralizers have become available. These solid typedevices can greatly help running of casing in extended reach wells. The rollersdramatically reduce the drag and torque in these wells. Below is an example ofthe use of these centralizers in an extended reach well, comparing the drag forcesto 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 themud in the hole as possible. Pipe movement is an integral part of best practices toobtain a good cement job.

From many large scale laboratory experiments and from field experiences, it hasbeen 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 androtation using scratchers has consistently shown little difference between the



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movement methods. The correct type of scratchers need to be used with eachtechnique.

For reciprocation, it is necessary to use the reciprocating (horizontal) cable looptype. 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 itis doubtful that they can perform downhole. In fact, the integrity of scratchers andcentralizers is a very important aspect. These items have to be extremely robustto 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 ratherthan performing their intended function. This does not detract from the philosophythat centralisation, pipe movement and mechanical disturbance of the mud cakewill 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 PumpRate, and 60% Pipe Standoff

Pipe Movement in Deviated, Highly deviated and Horizontal Holes

With reciprocation, the pipe may get stuck, potentially leaving uncased openholeat the bottom of the well. Reciprocation sometimes limits pipe movement to onlypre-cement job use. In this type of well, rotation has an advantage over reciproca-tion since, due to the torque forces, it tends to pull the fluids all the way around thepipe (better mud removal).

Recently, roller blade centralizers have been developed with rollers that reducethe torque during rotation. Those centralizers contain two sets of rollers. One setfor the reduction of drag during running of the casing, and another set to reducetorque to allow the casing to be rotated.

Pipe Movement for Liners

Rotation is the preferred way to move liners. Liner hangers are available that per-mit rotation of long heavy liners, and liner rotation has become common practiceeven for horizontal wells. With liners, rotation is preferred because it tends toovercome some of the potential disadvantages of reciprocation:

Pipe Movement Displacement Efficiency (%)

None 65

20 rev/min 97



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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 assoon as the casing or liner reaches bottom, and if possible, continue the pipemovement during hole conditioning and until cement is placed. Rotation shouldbe at least 10 to 20 RPM.

In the case that rotation cannot be achieved, for whatever reason, reciprocation ismuch 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 per-form surge/swab calculations to make sure the well is not damaged during pipemovement. In some slim hole applications, calculations may indicate that recipro-cation 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 notexceed the string tensile or torque limits, connection yield, the makeup torque ofthe weakest connection, or the load rating of the bearing in the liner hanger.

While reciprocating, the pipe should be lowered close to bottom occasionally, tokeep 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 dueto bump, or if it appears that the casing is going to get stuck, pipe movementshould 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 opera-tors. They include simulation of free-fall, calculate the circulating hydraulics,determine downhole pressures and attempt to take account of the mud displace-ment mechanics.

To produce a good simulation of the job, the actual well trajectory must be usedtogether with actual fluid properties and hole dimensions. Pre-job simulationsneed to be initiated as soon as possible - using assumptions - to help influence



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the job design. Re-runs can be made very easily with the latest data, to optimizethe 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 inva-sion 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 annu-lus.

When performing a pre-job simulation, the following information is needed amongother 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 com-pleted)

• 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 geom-etry as closely as possible to the real situation. This is of particular importance inslimholes, since relatively minor changes in hole geometry may make large differ-ences 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 forthe openhole section. Job pump rates are designed to stay below rates that mayinitiate lost circulation. Often the job is pumped fast at the beginning and then thepump rate is slowed to prevent the ECDs from exceeding the fracture gradientacross weak zones.



Cement Manual

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 thefracture gradient may often be more affected by the fluid rheology than by thedensity. This is because the contribution to the total pressure from the hydro-static component is smaller in these types of wells than in vertical holes. Againsimulators 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-bear-ing zones during the job, during potential shutdowns, and after placement of acement slurry.

To properly simulate the job, the depth and formation pressure (pore pressure) foreach liquid and gas-bearing zone must be known. If zones are not properly con-sidered, the result may be annular flow during or after cementing or even a blow-out.

When using preflushes, it is critical that the whole job be carefully evaluatedbecause of the loss of hydrostatic head which may be generated by these fluids,particularly if channeling occurs. This is important in narrow pore/frac windowwells, where low overbalance and the potential for gas migration is greater than inmore conventional wells.

12,600

11,0000 400 800 1,600

Volume In —bblPlot shows total annular pressure and equivalent circulating density

vs. liquid volume pumped into the well.

Circu

latin

g P

ress

ure

— p

si

Fracture pressure/gradient at 15,000 ft TVD

1,200 2,000 2,400

Fluids Pumped

➁ Dual Spacer

➂ Lead Cement

➃ Tail Cement

➄ Drilling Fluid

12,200

11,800

11,400

16

15

EC

D —

lb/g

al

➁ ➂➃

➄



Cement Manual

Example of a Job Simulation: A Slim Hole Situation

This section illustrate a slim hole cementing job simulation conducted using anindustry available job simulator. The Table defines the well configuration. Noticethat in this example, 3-1/2 in. casing will be set in a vertical 4-3/4 in. hole at a TDof 12,500 ft. The previous casing was 7 in. set at 1,500 ft.

Wellbore Geometry

Figure 16: Annulus Segments

Figure 17: Casing Segments

The Figure below gives the preliminary data for the fluids to be pumped. The topof the cement slurry will be at 6,000 ft to cover a gas zone located at 7,500 ft. Thegas zone has a pore pressure of 11.0 lb/gal equivalent and a fracture pressure of13.4 lb/gal equivalent. The fracture gradient equivalent at TD is 13.8 lb/gal for thishole.

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

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



Cement Manual

Figure 18: Fluid Properties for the Slim Hole example

The Figure below shows the erodibility calculations for the water-based mudwhich has an erodibility of 10. As mentioned before, an erodibility of 10 suggeststhat the PDG mud films from the mud are moderately hard to remove. This figureshows that for the spacer to remove the PDG, it needs to be pumped at about 3bpm. 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 4bpm, this suggests that PDG mud will likely be present across the permeablezones during the cement job.) Notice also in the same figure that the selectedrheologies of the spacer and cement slurry generate a pressure drop (wall stress)hierarchy going down in the annulus, starting with the mud. This suggests thatthere will not be a strong tendency for the fluids to channel if the casing is notproperly centralized (the exception is the water preflush, but the main function ofthis fluid is to help dilute the mud ahead of the main spacer, and it is expected thatit will be sacrificed/expended early during the displacement process).

Notice also from Figure that the cement slurry would be able to remove the PDGfilms if pumped at rates above 2 bpm. This is good news and bad news. The mud



Cement Manual

and mud films should be removed by the fluids ahead of the cement. Leftovermud will contaminate the

cement slurry. On the other hand, if the PDG films are removed by the slurry with-out drastically affecting the set properties of the cement, this would still providezone isolation. But again, this is not the ideal situation, and an effort should bemade to have the fluids ahead of the cement slurry do the removing of the PDGmud 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 removalby the spacer is 3 bpm for this cement job. However, as seen in the following fig-ure, using only 10 bbls of the water preflush, the job could not be pumped at thatrate. The Figure shows that at 3 bpm, the ECD at the bottom of the hole would goover 13.8 lb/gal before the end of the job.



Cement Manual

Figure 20: Job ECD's - 10 bbls Water

One thing that could be done is to increase the water preflush to 30 bbls (about3,000 liner ft in the annulus) to reduce the hydrostatic head. This would allow thejob to be performed mostly at 3 bpm, having to reduce the rate to about 2 bpmtoward the end. The obvious concern about running 3,000 ft of water in the annu-lus is the potential effect on the gas zone at 7,500 ft. The Figures shows that theECD at 7,500 ft never falls below 11 lb/gal pore pressure at 3 bpm. Even at 2bpm, the simulations suggest that the ECD across the gas zone would be above11 lb/gal, toward the end of the job, when the rate would be reduced to preventlost circulation. Using the 30 bbls of water, at the end of the job, the shut-in hydro-static pressure across the gas zone would be 11.7 lb/gal.



Cement Manual

Figure 21: Job ECD's - 30 bbls Water

The process of optimization outlined above indicates that the job could be donewithout losses, and that good PDG removal and minimum channeling would beexpected if the job is pumped at 3 bpm, and if 30 bbls water pre-flush are usedahead of the spacer to reduce the hydrostatic and to allow the rate of 3 bpm to beused.

One critical aspect to consider is the pressure differential of only 0.7 lb/gal (273psi) across the gas zone after the end of the job. This illustrates the high potentialfor gas migration after cementing in slimholes. With this low differential, the pres-sures in the cement column and the gas zone could cross (during the cementtransition time) before the cement has had time to develop enough gel strength toprevent 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 nextstep would be to design and use a good gas migration control slurry, and to try todo the job at the designed rates and with the optimized fluid properties, to obtain agood job.

Let us now look at the effect of erodibility. The Figure below shows the effect thata different mud with an erodibility of 5 could have on the outcome of this job (PDGmud films with erodibilities of 5 or less are very hard to remove). Notice that withthat erodibility, the spacer would have to be pumped at over 6 bpm to erode thePDG mud films. With that erodibility, none of the fluids would be capable ofremoving the PDG mud films. We already know, however, that those high rateswould be prohibitive in this hole due to great potential for lost circulation. With thelower erodibility, if the job was done at 3 bpm, thick PDG films would likely be leftagainst 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



Cement Manual

The Real World

When it comes to cementing a well, the hole may present conditions that will helpobtain a good cement job or the section may have elements that make obtaining agood cement job quite difficult.

Benign hole

A benign hole, from the point of view of cementing, has the following characteris-tics:

• 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,



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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 andunfavorable conditions. Because of this, sometimes compromises need to bemade 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, thecasing was assumed to be completely centralized. Perfectly centralized pipe pro-duces higher frictional pressures than eccentric pipe. The ECD figure belowshows the ECD's generated for the same slim hole situation, if the pipe waseccentric (against the wall). As can be seen, the calculated ECD's are muchlower than for the centralized case. Obviously not centralizing the pipe to reducefrictional pressures is not an option because non-centralized pipe will cause chan-neling and a poor cement job. Additionally, in a real job, channeling would raisethe hydrostatic pressure, potentially causing the total well pressures to be higherthan for the centralized case.



Cement Manual

Figure 23: ECD's with 10 bbls Water - Pipe Eccentric

Reactive Formations

Hole sections containing reactive formations are often drilled with oil based fluidsto minimize hole problems such as sloughing, large washouts, etc. Depending onthe degree of reactivity of the formations, they may react when contacted with thewater base spacer during the cementing operation. A few formations can be soreactive that they have been called 'explosive' when contacted with water.

In the case of reactive formations, it is important to conduct tests in the laboratoryusing samples from the well (cuttings, cores) to carefully optimize the design ofthe spacer system. Cases have been documented where the use of 3 - 5% KClin the spacer and the cement slurry have led to higher quality cement jobs.



Cement Manual

One thing that helps with this situation is that normally the length of time thesereactive formations are contacted by the water base spacer and the cement slurryis very short when compared with the time needed to drill the hole section (a fewhours vs. days). However, there are cases where the TOC places the spacer inopen hole forever.

Fluids Left Behind the Casing

One issue associated with cementing of wells that is often ignored is the effect ofthe fluids left behind the casing after the cement job. Often cement is not circu-lated all the way to the surface, particularly when cementing the deeper strings ina well.

Depending on the well conditions and the properties of the fluids in the annulusabove the cement column, the fluids may tend to segregate, and potentially cor-rode the casing. Segregation/settling may lead to annular flow during the life ofthe well (loss of hydrostatic), if the fluid is across zones with potential for invasionof the annulus. Corrosive effects may eventually cause casing leaks at somepoint during the productive life of the well. Thus, all fluids left behind the pipeneed to be examined to make sure they will not negatively affect the integrity ofthe casing strings during the life of the well.

If WBM is to be left behind casing, the pH should be raised and, perhaps, an oxy-gen scavenger used.

Fluid Contamination in the Casing

A bottom plug has two main functions. One is to wipe the mud film from inside thecasing wall ahead of the cement to prevent slurry contamination. If not used, themud film may be wiped by the top plug, potentially displacing that volume of mudand contaminated cement into the shoe track. As an example, a 1/16" mud film in15,000 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 toprevent 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 rubberdiaphragm, to reduce concerns when using loss circulation materials. Underpressure differential, the disk breaks into small pieces.

The potential for fluid contamination is greater with the larger casing strings. Thelarger the casing, the greater the potential for contamination in the casing if bot-tom plugs are not used. In practice, when pumping a large volume of lead slurryon a surface casing string, the bottom plug can be omitted. Plugs for large casingstrings – eg 18 5/8” and above can be insufficiently robust to adequately perform



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the job. Bottom plugs should be used whenever possible. Best cementing prac-tices call for the use of several plugs. For example, one separating the mud fromthe 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. Thelonger the shutdown to release plugs, switch lines or tanks, etc, the higher thepotential negative impact on the job. Shutdowns cause gelation and dehydrationof the drilling fluid in the hole. Therefore, every effort needs to be made to mini-mize or eliminate shutdowns during conditioning of the hole and during thecement job. To eliminate shutdowns to drop plugs, the industry has developedseveral 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 Col-lection below) are not connected to the output of the rig pump. One serious effectof this is that no permanent record of the job is collected when displacement isdone with the rig pumps. In addition, if the assumed efficiency of the rig pump isnot correct, the displacement volume may be in error. Where accurate displace-ment volumes are needed then the cementing unit should be used.

Job Monitoring

Proper monitoring of the job, comparing the measured against the predictedbehavior, can assist tremendously in deciding if the well is experiencing loss circu-lation. Additionally, a permanent, continuous job record is essential to be able toperform 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 conven-tional hole, primary cementing processes.

Cement Slurry Design - The cement slurries used in slimholes must have somevery special properties. For example, the slurries must have rheologies lowenough such that they can be mixed and pumped at reasonable rates withoutcausing breakdown due to excessive ECDs in the narrow annuli, but withoutexhibiting stability problems. In addition, the slurries need to contribute to prop-erly displacing the drilling fluid from the annulus without dropping solids, particu-larly in deviated configurations. The narrow configurations generally dictate thatthe slurries need to have good fluid loss control and, in many instances, good gasmigration control properties.



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Slurry Placement - To take advantage of the erodibility technology, it is usuallyadvantageous to pump at high annular rates for optimum displacement and toremove as much as possible of the partially dehydrated-gelled mud in the well-bore. Although smaller annular clearances increase the annular wall stresses fora given pump rate, there is also the problem of larger than conventional circulatingpressures generated by the high rates. This leads to elevated equivalent circulat-ing densities (ECDs) and the possibility of lost circulation. Thus, the properdesign (fluids' rheologies, pump rates, etc.) for pre-job hole conditioning andcement slurry placement is one of the most critical aspects to successful cement-ing in a slimhole. Operational Issues - Slimhole drilling leads to the use of much smaller slurry vol-umes for cementing. This helps keep down the overall cost of the job, but alsomeans more time and effort spent in the cement slurry design and testing phase,and special care during cement mixing and displacement. Due to the smallcement slurry volumes used, even small amounts of contamination while mix-ing/displacing the cement slurry may dramatically affect the properties of thecement such as the thickening time, strength development and the WOC time.The narrow annuli also means that the volumes of spacers and washes must becarefully designed to make sure adequate annular coverage and fluids separationtakes 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 wellcontrol is maintained during the cementing operation. Gas Migration - Due to small annular clearances and possible low overbalancepressures, potential for gas migration after cementing in slimholes is often signifi-cant. A slimhole may require more specialized gas migration control cementslurry design and field practices than a conventional well at the same depth. Thespecific hole to be cemented needs to be analyzed in detail and the cement slur-ries used need to meet critical gas migration control criteria verified by laboratorytesting.

Pressure Drop Across Liner Hangers and Polished Bore Receptacles

Attention needs to be given to the configuration (OD's) of liner hangers and PBR'sin relation to the ID on the previous casing, when preparing for liner cementingoperations. Very large pressure drops can be generated across these tools if theannular clearances are narrow. This can cause a "piston effect" when runningthe liner, potentially fracturing exposed weak formations. Surge/swab simulatorsneed to be used to check the configurations and/or to decide on the casing run-ning speeds to avoid well damage. High pressure drops across liner hangers andPBR's are bad enough. However, the worst potential problem is the bridging ofthe narrow clearances across the tools. Bridging can easily occur from cuttingsand/or other particles present in the well fluids even after hole conditioning. Holecleaning and mud conditioning prior to running pipe is the key to success.



Cement Manual

Liner Top Packers

Liner top packers are frequently used to provide a seal at the top of liners. Theymay be run either as an integral liner top packer; in which case setting takes placeat the end of the job prior to pulling out with the running tool. Alternatively, they arerun on a separate trip. Integral packers have become popular because they avoidthe need to drill cement from the top of liner. Immediately following the job thepacker is set and cement is reversed out. The packer avoids transmitting thehydrostatic pressure to the annulus which could lead to formation fracture.

The use of such integral liner top packers needs to be carefully considered, partic-ularly when permeable zones of unequal pressure are covered by the liner. If thepacker is set soon after completion of the cement job, and assuming packerdoesn’t leak, it then effectively shuts off the hydrostatic head on the cement col-umn in the annulus. As fluid is lost from the cement slurry below the packer (innershrinkage due to hydration), a pressure drop will occur in the unset cement col-umn, greatly increasing the potential for fluids invasion. The end effect is that gasis trapped below the liner top and is often apparent on USIT logs. This may bedetrimental later on in the life of the well. Zones of unequal pressure maycross-flow.

Reverse Circulating Cementing

Reverse circulation cementing has been used in relatively shallow wells (around2,500 ft), but some applications have been reported to depths near 9,000 ft. It hasalso 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 cir-culation. The valve closes when the inner string is un-stung at the end of thecement job.

Reverse circulation cementing may be a very viable alternative to conventionalcementing practices in situations where weak formations may be broken downduring normal cementing. Reverse circulation cementing may generate muchlower job pressures across the open hole in slimhole cementing.

Some float equipment has been developed to allow such reverse jobs without theneed for an inner string, extending the potential application to deeper casingstrings. There are many objections to Reverse Circulation Cementing, e.g:

• Unconventional

• Conventional float equipment cannot be used.



Cement Manual

• 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 condi-tioning 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 bot-tom 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 andpressures likely to be seen during such jobs. The effect of geometry must beinvestigated.

Liner Cementing Considerations

Aspects that differentiate liner cementing from conventional primary cementinginclude:

• 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 haveindicated that the best results are obtained with annular clearances of 1 to1 ½



Cement Manual

inches. Depending on well configuration and mud properties, large annular clear-ances may be detrimental to success, if at reasonable pump rates, not enoughstress can be applied to remove gelled mud.

With liners, annular clearances are normally small. In many liner applicationsannular clearances are ¾ " or less. Many successful liner operations have beenperformed with clearances of ¾ " (for example 7" casing in 8 ½ " hole) but inmany cases caliper logs shown holes larger than 8 ½ ".

When annular clearances fall below ¾ ", the cementing success ratio falls. Evengetting the liner to bottom within the pore/frac window may be difficult. Centraliza-tion is a challenge and the use of very expensive centralizer subs may be neces-sary. An alternative is to under-ream the hole.

Temperature Considerations

In cementing full strings of casing, the cement performance concerns are mainlyacross the producing zones near the shoe. On liners, the cement must also setand 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 thanthe circulating temperature at the bottom. Therefore, an accurate understandingof the well temperatures is necessary for designing the cement slurry.

Mud Removal

Mud removal and avoidance of channeling are vital. Experience has shown thatthe chance of sealing the overlap is improved if excess cement, sufficient to fillabout 500 ft of the drillpipe/casing annulus, is used. This excess volume can con-tribute to removal of the mud from the overlap and is normally sufficient to ensureall the contaminated cement slurry is out of the overlap.

Sufficient spacer volume should be used to give a contact time of about 10 min-utes. Another ‘rule of thumb’ is to use enough volume to provide about 800 ft ofannular length to assist with mud removal. Weighted spacer should be mixed at adensity between that of the cement and the mud. If the mud is oil based, thespacer formulation must contain surfactants to water wet the pipe. The spacershould not exhibit settling which could cause the drill pipe and running tool to getstuck above the liner top.

It the liner is to be hung prior to cementing, it is a good practice not to set the linerhanger until bottoms-up have been circulated above the liner top. Setting the linercan reduce the flow path by as much as seventy percent. Debris can bridge thisrestriction and cause loss of returns.



Cement Manual

Liner Equipment

Detailed equipment information is given in another section of this manual. Herewe will only briefly review this topic. In most liner cementing operations, a floatshoe, a float collar and a landing collar are used. The use of redundant floats is toprovide backup to prevent flow back of the cement slurry into the liner at the endof the job (U-tube effect). Some liner shoes incorporate multiple floats as anadded safety measure. At least two joints of casing should be used for the shoetrack, so that any contaminated cement slurry will be left in the liner rather thanaround the shoe.

Liners should be centralized whenever possible. The difficulties in obtaining ade-quate cement coverage in liner applications due to narrow annuli is tremendouslyaggravated if the liner is not centered in the hole. Expensive solid blade or bowcentralizer subs may be the only way to centralize the pipe in very narrow configu-rations (3/4 inch or less). These sub-type centralizers are made up as part of thecasing string.

Job Execution

Movement of the pipe should be incorporated whenever possible. If it is not feasi-ble to move the pipe during cementing, the pipe should be moved while condition-ing the mud.

Overlap Length

In shallow, low pressure well situations, relatively short liner overlaps (300-400feet) may be adequate to provide an effective seal. In deep, high pressure gaswells overlaps of 450 to 800 feet may be required. It has been reported that over-lap lengths of less than 300 feet require more remedial cementing than overlaplengths 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 topwith cement:

• single stage

• planned squeeze

When using single stage cementing, the cement slurry is circulated around theshoe, up the hole and through the liner lap. If a planned squeeze is used, theslurry is circulated to a pre-determined point below the liner top and the liner top isthen squeezed during a second operation. This approach is used when the forma-



Cement Manual

tion cannot support the ECD developed during placement. Squeezing the linertop may require another trip. Whenever possible, the single stage method shouldbe 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 for-mation 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 linerjob can be considered a success. Before this overlap seal can be tested, thecement 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 obtainan 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 theliner top for fear of collapsing the liner during liner top testing. If the liner top is tobe tested before the liner has been cleaned out, the maximum load to be appliedto 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 theliner has set and developed a predetermined amount of strength (normally about500 psi). Compressive strength tests in the cement laboratory prior to the job willindicate 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 hotterthat the static temperature at the liner top, extended WOC times may be neces-sary. Operators on expensive offshore rigs sometimes attempt to shorten theselong WOC times by reentering too soon, only to lose several days to squeezeoperations. To decide on the test pressure of the liner overlap, severalapproaches 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 previ-ous casing shoe in order to determine if there is a seal.



Cement Manual

• Sufficient test pressure should be applied to make sure further drilling opera-tions are not impaired.

• When drill stem or other testing is to be performed on lower zones, the over-lap 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, inmany cases, the flow of fluids in one direction, while restricting flow in the oppositedirection. This may also be caused by debris in the overlap that may act likeflow-check valves. If this conditions exists, it is possible to obtain a sufficient pos-itive pressure test and still have gas flow into the wellbore. For this reason, it isalways prudent to also conduct a negative test. This test is sometimes called a drytest or a differential test. It involves the relief of a portion of the well hydrostaticpressure in the wellbore.

A retrievable squeeze packer is generally used for a negative test but a drillablepacker can also be used. The packer is run in the hole on a work string (usuallydrillpipe), to a depth above the top of the liner. After setting the packer and con-ducting a positive pressure test, the bypass circulating valve on the packer isopened and drill water or diesel is pumped into the drillpipe, displacing the wellfluid until a sufficient differential pressure is obtained. With the valve closed andthe packer set to isolate the well fluid in the annulus, the differential pressure isbled off leaving the hydrostatic pressure of the fluid contained in the drillpipe onthe liner top. Flow back is monitored to determine if a leak is present. After 15 to30 minutes with no flow, the drillpipe is then re-pressured to the amount of the dif-ferential. The packer valve is opened again and the light fluid in the drillpipe isreversed out and again replaced with well fluid. The expansion of cool water afterplacement in a hot well will cause some flow and this should not be confused withactual well flow.

A sufficient amount of differential would be the equivalent to the expected lightesthydrostatic to be incurred during subsequent drilling and eventual productionoperations. If this value is unknown, a 2000 psi differential is usually adequate. Inall 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 lifeof 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



Cement Manual

should be used. Only one plug is used probably 80 percent of the times whencementing tieback strings to surface. As pointed out before, in large casingstrings, if a bottom plug is not used, severe channeling inside the casing canoccur, 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 holewith the tieback casing string. Many operators want to make sure the tiebackstem is stabbed into the tieback sleeve prior to cementing. However, it is possiblethat the stem is pumped out during the cementing process due to the coolingeffect of the circulated fluids. In order to protect the seals on the tieback stem, thepressure should be released and the surface left open when lowering the steminto the tieback sleeve. If the tieback stem seals fail, pressure needs to be held onthe 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 arepumped as designed - particularly the cement. The slurry density data is criticalfor analyzing the quality of the cementing operation even if the slurry is batchmixed. This information should be recorded continuously using an on-site com-puter system.

The Pump Rate

The flow rate data helps estimate the displacement efficiency of the cementingjob. To maximise displacement, the spacer and cement slurry must be pumpedat the designed flow rates. In addition, the pump rate data can help with the cal-culation of the volume of the cement slurry placed in the well. This volume ofcement pumped into the well is critical to analyze the cement tops and the possi-bility of channeling (along with the job pressures

The Surface Pressure

The job pressures are critical for the analysis of the cementing success. Thepressure can provide a good idea of the circulating hole volumes, as well as topoint out problems during the circulation of the cement like channeling, lost circu-lation, etc.



Cement Manual

Service Company Cementing Software

Software

Introduction

This Section includes service company descriptions of their cementing job com-puter simulators.

Schlumberger

CemCADE

Computer-Aided Design and Evaluation for Cementing

CemCADE simulates a set of pumping conditions in a given well, but it is muchmore than a mere U-tube simulator. CemCADE is fully integrated software con-taining different modules where all aspects of a cement job are accounted for.Dynamic graphics are automatically updated with any change of data and a num-ber of independent calculators further help the user selecting the appropriatecementing job parameters.

U-tube and placement

The U-tube simulator is an analytical tool, which calculates free-fall and ECDusing the rheology of fluids at the temperature selected by the user (see Labora-tory database). This is normally the temperature output by the temperature simu-lator. This U-tube simulator has been validated against field measurements wherereturn flow was measured.

The user inputs the different fluids, either by volume, or height (fill-up), or dynami-cally on the graphics. A comprehensive set of graphs is selectable.

Pauses in the pumping schedule can be included at any stage in order for theU-tube simulator to realistically simulate the movement of fluids during eventssuch as dropping plug, switching tanks or silos… Output can be selected versustime or volume.


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The user is then able to easily verify that the well is kept under control at all timesduring 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-backcasing…

In the case of a liner, CemCADE also simulates circulation of excess cementabove the hanger, after the cementing operation, if a liner packer does not exist toprevent transmission of applied annular circulation pressure through thecemented annulus.

Input data

In order to achieve this first objective of well control, CemCADE is fully integratedin the Drilling Office software suite. Not only can CemCADE read full survey andcaliper data (imported as ASCII files), but this well data can be automaticallydownloaded from the Drilling Office database. Hence these caliper and surveytables can have several hundred lines of data.

A pipe database is available, but the user can define his own casing and drill pipestrings.

Formation description (rock and fluid types, pore and frac pressures) is alsodescribed in a table containing as many lines as information is available. This datais 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 fluiddata can be searched locally as well as through the network. All tests for givenslurry are automatically retrieved. Rheology is measured at different tempera-tures. The user then selects the rheology, which will be used in the simulations: hewould particularly choose the rheological parameters measured at the tempera-ture 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 cen-tralizers. Different types of centralizers (rigid, bow, semi-rigid…) can be combinedat will. Centralization is calculated for a given distribution of centralizers, or thesimulator proposes a distribution in order to achieve a given minimum desiredstandoff. The standoff is calculated not only at the centralizer, but also betweencentralizers, in order to account for the deflection of the beam under its ownweight. Drag force while running the casing with the selected distribution of cen-tralizers 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 propertiesfor the fluids pumped, so that each fluid will effectively displace the preceding onein the chosen flow regime, as a function of eccentricity, deviation, hole size… Thecriteria must fulfill the WELLCLEAN eccentered mud removal technology.

Once the fluid properties have been selected, the U-tube simulator and the cen-tralization calculations are run. The Mud Removal simulator will then output theefficiency (versus depth, and time for turbulent flow or volume for Effective Lami-nar Flow) at which the preflushes displace the drilling fluid, and the slurries dis-place the preflushes.

Aids for Design of Effective Laminar Flow Displacement

This module helps the user selecting dynamically and graphically the optimumproperties for the displacing fluid for efficiently removing the displaced one, as afunction of annular geometry, deviation and pipe standoff.

Evaluation of the Mud Displacement Process

A 2-D numerical simulator visualizes the fluid displacement. Channels and filmson walls are identified. Primarily an evaluation tool, this simulator can be used indesign mode.

Cement Job Evaluation

CBL Adviser

The CBL Adviser module helps in evaluating cement bond logs, accounting for allwell parameters and outputs the referenced CBL amplitude for the given cement-ing operation.



Cement Manual

Post-Job Evaluation

CemCADE uses the recorded job data to simulate all the operation using thesejob parameters. This simulation of the operation using the execution data allowsto identify problems that occurred during the operation, by comparing the Job Sig-nature with the simulated curves. Typical problems are hole instability and annularclosure, fluid channeling and losses. Subsequent cementing operations cantherefore take into account the occurrence of such events, and the design can bemodified accordingly.

Temperature Simulator

In addition to handling multiple temperature gradients, this analytical tool accountsfor well deviation, annular geometry, type of formations, fluid rheologies and flowregime. Above all, pump rate and time are key factors in these heat transfer phe-nomena. CemCADE’s temperature simulator was validated by field measure-ments made in the early 1990s in onshore and shallow offshore wells. CemCADEtemperature simulator has now been validated in deep water conditions andrequires the input of the temperature profile and the current profile in the columnof sea water.

Temperature simulators are therefore recommended when well conditions deviatefrom vertical or when a particular pumping schedule is planned to cool the well, orin deep water wells, as the API schedules cannot handle these situations.

The output of the temperature simulator is used for the laboratory to optimize thefluid properties. It is used also to recommend, particularly in HP-HT wells, a mini-mum circulation period prior to cementing not only for cleaning the wellbore, butalso for establishing a flat temperature profile versus depth. This ensures that allthe fluids pumped will keep their properties as designed.

Plug Cementing

A plug cementing module helps designing the conditions for increasing the effec-tiveness of placing cement plugs off bottom. This tool recommends a certain rhe-ology 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 highlyinclined wellbores.

The placement of the cement plug is also carefully considered in order to optimizemud removal and avoid overdisplacing the fluids, particularly when using taperedstrings. Recommendations are for fluid volumes and rates in order to keep stableinterfaces between each fluid, inside and outside the drill pipe, and after havingpulled the pipe.



Cement Manual

NOTE ON MUDPUSH:

MUDPUSH XL applies the Effective Laminar Flow (ELF) technique, which com-bines several criteria to achieve optimum mud removal at low flow rates. For along period of time, the oil industry has considered only two suitable flow regimesto achieve proper mud removal: Turbulent Flow and Sub-Laminar Flow (alsocalled Plug Flow). The reason very often put forward for promoting Plug Flow andavoiding Laminar Flow is based on the confusion between the velocity profile of agiven fluid and the interface profile between two fluids. Although the exactdescription of this interface is not yet fully known, it is recognized that, under cer-tain conditions, the interface profile can be quite flat even in Laminar Flow. One ofthese conditions, which is also our first criterion of the Effective Laminar Flowtechnique, is the well-known Density Hierarchy between the Displaced and Dis-placing fluids. In other words, the slurry density must be higher than the spacerdensity, and in turn the spacer density must be higher than the mud density. Asthe density differential between the displaced and displacing fluids increases, theirinterfaces 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 generatedby the flow of the Displaced and Displacing fluids. To increase the stability of theinterface, this criterion recommends that the friction pressure generated by thedisplacing fluid be greater than the friction pressure generated by the displacedfluid. This is equivalent to having, for a given annular geometry and flow rate, theapparent viscosity of the displaced fluid lower than the apparent viscosity of thedisplacing fluid.

The third criterion, often referred to as the MPG (Minimum Pressure Gradient) cri-terion, verifies the mobility, in an eccentric annulus, of the displaced fluid providingthis fluid exhibits a yield stress. The fourth and last criterion is called the Differen-tial Velocity criterion. In an eccentric annulus, a single fluid will always flow fasteron the wide side (the path of least resistance) than on the narrow side. This crite-rion imposes that the displacing fluid does not flow faster on the wide side of theannulus than the displaced fluid on the narrow side.

These four criteria have been implemented within the CemCADE program and theacceptable range for annular flow is the output. For a given set of conditions, theminimum annular rate calculated by the CemCADE program equals the highest ofthe following values:

• Minimum rate for MOBILITY on the narrow side of the casing for fluids exhib-iting a yield stress (MPG criterion)

• Beginning of the 20% friction pressure hierarchy

• Arbitrary lower limit of 1 bbl/min



Cement Manual

• Beginning of the stable front between the large and narrow sides of the cas-ing (velocity criterion - optional).

• The calculated maximum annular rate equals the lowest of the following val-ues:

• End of the 20% friction pressure hierarchy

• Full establishment of turbulence by the displacing fluid (turbulent-flow place-ment 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 theirdensities, pipe and openhole geometry, pipe eccentricity, and well deviation.Within the MUDPUSH family (XT for Turbulent, XL for Laminar and XS for SaltSystems), the viscosifiers used are special products that enhance each system’scharacteristic. The D149, for instance, allow a wide range of PV and Ty under dif-ferent concentrations on the XL spacer, this behavior is not exactly found on otherviscosifiers.

Halliburton

OptiCem

A Primary Cement Job Simulation Program

OptiCem - is a primary cement job simulation program. Any type of primary jobcan be simulated. OptiCem takes into account all known cementing factors. Mudchanneling, eccentricity, freefall, mud compressibility (inthe works), temperaturedependant rheology, gas expansion and compression,change in viscosity withchanging foam quality, Tuned Spacer, hookload, etc.

Mud channeling

OptiCem calculates the forces required to remove mud and then compares therequired forces to the force present under the planned job scenario and predictswhether the mud will be removed or not based on these relative forces.



Cement Manual

Eccentricity

OptiCem can calculate frictional pressure losses based on concentric pipe oreccentric pipe. The standoff of the pipe for these pressure calculations can beentered as a single fixed number or be dynamically calculated based on theplanned centralizer program. Thus the level of eccentricity is allowed to vary upand down the entire wellbore, if the design requires that level of accuracy.

Freefall

Freefall is important with the larger surface and conductor strings when cemententers the annulus, these strings may become buoyant. Prior knowledge of this iscritical for the success of the job and the safety of those present on location. If therig is near capacity do to string weight, knowing the maximum weight when thecasing is full of cement is also critical for the success of the job and the safety ofthose present on location. Pressures acting on all shoulders, lateral forces, anddrag stresses are all considered.

Mud compressibility (in the works)

Many of the new mud systems are compressible enough that there changes inboth volume and density become significant. The next release will contain PVTcorrelation's for a minimum of 6 different base fluids and the algorithms that willchange 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 themost sophisticated WellCat simulation as input. If a single rheology data point isentered that rheology will be applied to the entire wellbore. If rheology data isentered at two or more temperatures, OptiCem will thin the fluid on the way downthe casing and then thicken it as it cools on the way up the annulus. These contin-ually adjusted rheological parameters will be used to calculate the frictional pres-sure drops.

Tuned Spacer

OptiCem's Tuned Spacer wizard allows the user to tune the spacer's rheologicalproperties to the given well conditions. If the properties are entered to match thewell conditions, the tuning process will provide sufficient levels of shear at the wallto remove the gelled mud.



Cement Manual

Gas expansion and compression

In foam cementing the gas must be allowed to expand and contract as the pres-sure and temperature changes. As the gas changes volume the internal flow ratewill change in unison. As the foam quality increases the fluid density hydrostaticpressure decreases. OptiCem takes all of these factors into account when deter-mining ECD. To properly design a foam job the N2 concentrations and base slurryvolumes must be infinitely adjustable to allow the user to get the proper amount ofdown hole volume and the required density profile. To know how to adjust theseparameters the user must know how much down hole volume results from theplanned job process and what the final density profile will look like. OptiCemallows the users to easily adjust these data and provides the results required tocorrectly make these adjustments.

Change in viscosity with changing foam quality

As the foam quality increases so will the viscosity. To accurately model foam vol-umes and densities the user must accurately model pressures. OptiCem usesthese adjusted rheologies to modify the frictional pressures.

Hookload

With large surface and conductor pipes after the heavy tail enters the annulus thepipe can become buoyant. If the pipe floats out of the well the job will be a failureand the safety of the rig personal will be at risk. When the hung pipe weight isnear the rigs maximum the added weight of the cement might exceed the safeoperating range for the rig. If the rig collapses, again the job will be a failure andthe safety of the rig personal will be at risk. OptiCem takes into account the forceson all of the shoulders, the lateral forces, and the drag stresses.



Cement Manual

BJ

CMFACTS

Primary Cement Design, Analysis and Real-time Monitoring Program

The following is intended to be a brief overview of the simulator methodology andfeatures. The simulator calculations make some general assumptions.

1) Base slurry properties remain constant (through shear/temperaturechanges).

2) Temperature gradient (for foam calculations) is linear.

3) Flow characteristics of a nitrified fluid can be extrapolated from the basefluid.

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 cal-culated return rates.

The simulator tracks up to 300 fluid segments in the pipe and annulus. Fluid seg-ments account for varying density and/or gas ratio.

Pressure calculations are performed iteratively at certain time intervals. Inputparameters are slurry rate in and slurry density in. Surface pressure at the well-bore is assumed, and pressures along the flow path are calculated, accounting fordiameter changes, down the pipe and up the annulus. Iterations are performeduntil calculated return pressure is sufficiently close to the specified or measuredvalue. If the iterations result in negative surface pressure, this is accounted for byfree-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 thejob.



Cement Manual

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 ECDand Reynolds charts, wellbore diagram, fluid inventory, mud place-ment/displacement graphic etc.

10) User can pause or slow down simulator and manually control keyparameters (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 arenot integrated into the flow calculations.



Cement Manual

Mud Preparation and Removal

Introduction

Mud has a critical role and will influence the performance of cementing opera-tions. The mud will be responsible for the condition of the wellbore and the qualityof the displacement to cement, which in turn will influence its long term.

Good mud engineering will create the environment that will allow for the smoothinstallation of the casing or liner, the mud displacement and the quality of thecement seal and casing support.

Wellbore Conditioning

While the displacement from mud to cement is critical, the condition of the well-bore in preparation for the cement is also extremely important.

A conditioned wellbore will have been drilled with mud that has an efficient sealingcapacity, 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 ensurethe hole is clean and all drilled cuttings and cavings have been removed. Thedirectional drillers will have taken the bit to target leaving the hole with limited tor-tuosity and minimal doglegs.

The filter cake is the man-made membrane formed behind the bit on the wall ofporous formations. This membrane will contain a sample of all the solids in themud and its thickness will reflect the relationship between the rock pore throat orfracture size and the particle size distribution of the mud.

Formations with a large pore throat size and mud loaded with only very small par-ticles 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 featuredthroughout the drilling process. In the following table mud characteristics areexplained with regard to the drilling and casing/cementing operations.


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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 con-ventional mud tests”

The mud should be designed to build the thin nest possible filter cake against all the differing porous forma-tions, providing better trips, lower annular pressure drops and reduced risk of stuck pipeFilter 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 mini-mal 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 per-formance.A thin filter cake will enhance cas-ing 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 maxi-mise the benefits of the hydrostatic force and improve wellbore stabil-ity; a stable wellbore has fewer washouts.

Viscosity “Lower Plastic Vis-cosity 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 clean-ing and a clean hole prior to cementing will reduce the risk of losses caused by a build up of sol-ids 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 nar-row annulus.Progressively increasing Gel strengths pre vent mud flow in washouts and take more pressure to initiate flow, resulting in channel-ling.

Solids Content“Low Gravity Drilled solids”

Poor size distribution and high vol-ume will make viscosity more difficult to control.Poor size distribution and high vol-ume 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 willrequire that the highest standards be maintained. The engineer must specify theproperties that are to be reported and agree with the contractor how much latitudeis allowed, as slippage is inevitable. All fluids used to drill will deteriorate and it isthis deterioration that must be controlled.

The mud used to drill will be either oil or water based and there are important dif-ferences, which must be understood and taken into account during the planningprocess.

Cementing in Oil Based Mud (OBM)

Viscosity

Oil based muds derive limited viscosity from the base oil and submicron-sizedemulsified water, but this viscosity will be Newtonian in character. The majornon-Newtonian rheology is derived from organophilic clays (also known as organ-oclay). These are bentonites in which the inorganic exchangeable cations, suchas sodium, calcium and magnesium, have been displaced by fatty quaternaryamines.

Low-Shear-Rate Viscosity

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

Drilled Solids

Since there is, as yet, no reliable method of removing colloidal size particles fromoil-based muds, these solids tend to build up in the system, eventually affectingthe mud properties. High plastic viscosity values and elevated low gravity solidscontent are indicators that the mud is contaminated. The longer the oil mud hasbeen in use, the more colloidal size solids will have accumulated. Althoughremoving solids with solids control equipment, particularly with the centrifuge, mayhelp, colloidal solids cannot effectively be removed mechanically. In this case,



Cement Manual

dilution with base oil is the only recourse.

Dilution can be minimised, however, with the use of a good solids control programto remove as many solids as possible before they degrade to colloidal size. Fortu-nately, oil mud does not allow degradation of the solids to occur as rapidly as itwould in water-based mud.

The Cement Job

To assure a good cement job with oil-based mud, we recommend careful adher-ence to the principles outlined in this section. Some of the difficulties outlinedbelow will help you understand why these measures are so important.

Cement slurries and oil-based mud are extremely incompatible. These two fluidsform very viscous masses when they come in contact with each other. The pres-ence of these viscous masses makes the displacement of the mud from the holeduring the cementing operation very difficult.

Since most oil-based muds contain salt in the aqueous phase, any mud left in thehole and contaminating the cement slurry may significantly affect the thickeningtime of the cement. In a well drilled with stable water-in-oil emulsion mud the cas-ing and the formation are preferentially oil-wet. Since cements do not bond to oilysurfaces, it is necessary to reverse this preferential wetting. Oil-based muds tendto be run with lower gel strengths which contribute to better displacement, andfinally, the good fluid loss control properties associated with oil-based muds gen-erally produces a thin, firm filter cake which is also favourable to the displacementprocess.



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As mentioned above, the surfaces in wells drilled with oil-based muds are nor-mally oil wet and cements will not bond to oil wet surfaces. We must do everythingpossible to assure that all of these surfaces are water-wet before the cementslurry contacts them. This factor makes flush/spacer design and placement a criti-cal element in achieving a successful cement job in a well drilled with oil-basedmud.

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 con-tain 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 incompati-ble. While this is not so true for water-based mud, water based mud does presentother problems.

Cement contamination drastically changes the nature of freshwater, clay-basedsystems. The calcium ion tends to replace sodium ions on the clay surfacethrough a Base Exchange. The bound layer of water on the clay platelets isreduced, resulting in diminished hydration or swelling characteristics. The effect ofcalcium contamination on deflocculated muds is increased fluid loss, yield pointand gel strengths.



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The potential for contamination during the displacement must be a prime concernand 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 treat-ment is required it may take the form of a dilution, but when minimal disturbanceto filtrate control and inhibition is required, a treatment with an approved defloccu-lant 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 factthat we know ahead of time when we will be drilling cement. The physical andchemical indications of lime or cement contamination are; increased yield pointand fluid loss, increased pH and alkalinities, and a possible increase in calcium.The calcium increase may be masked, however, by pH. Gypsum and anhydritecontamination is also characterised by an increase in yield point and fluid loss, asthese effects are the result of the divalent cation (Ca ++) in the mud. Alkalinitiesand pH decrease with anhydrite contamination because CaSO4 and H2O liberateH + ions. An increase in detectable Ca ++ is also likely since there is not a high pHto limit its solubility.

Approximately 100 mg/L of Ca ++ should be left in the system to react with carbon-ate ions.

In most drilling operations, cement contamination occurs one or more times whencasing strings are cemented and the plugs are drilled out. The extent of contami-nation and its effect on mud properties depends on several factors. These includesolids content, type and concentration, deflocculants, and the quantity of cementincorporated. One 94-lb sack of cement can yield 74 lb of lime. When cement iscompletely cured only about 10% is available whereas, when it is soft (green) asmuch 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 associatedwith cement contamination.



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Viscosity

Freshwater bentonite systems are flocculated by cement, resulting in increasedviscosity and fluid loss. The severity of flocculation depends upon the quantity andquality 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 mostcases the suspension will be sensitive to cement as it contains high concentra-tions of calcium and hydroxide ions, both can be detrimental. Calcium will causeflocculation of clays while elevated pH (>11.5) will cause the degradation of mostviscosifying 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 suchas cement, because excess solids and contaminant ions can strongly interact tocreate a more serious mud problem than either one separately.

High plastic viscosity values and elevated low gravity solids content are indicatorsthat the mud is contaminated. Although removing solids with solids control equip-ment, particularly with the centrifuge, may help, colloidal solids cannot effectivelybe removed mechanically. In this case, dilution with either water/brine or wholemud is required. Dilution can be minimised, however, with the use of a good solidscontrol program to remove as many solids as possible before they degrade to col-loidal size (see section on solids control). Unfortunately, water does allow degra-dation 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 carefuladherence to the principles outlined in this section.



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Cement slurries and water-based muds are incompatible, but unlike OBM wherethe two fluids will form a very viscous interface when they come in contact witheach other, most WBM’s will not interact so severely. It is only WBM’s containinghigh 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 thehole during the cementing operation difficult.

Some water-based mud contain salt, therefore, any mud left in the hole and con-taminating the cement slurry may significantly effect the thickening time of thecement. In a well drilled with water-based mud, the casing and the formation willremain water-wet and present no problems with regard to wettability.

Water-based muds tend to be run with higher gel strengths which contributes topoor displacement, and finally, the fluid loss control properties associated withwater-based muds generally produce a thick, soft filter cake which is also unfa-vourable 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-basedare:

• 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 dis-placement process and to remove as much of the mud as possible, ahead of thecement slurry.

To maintain control of the well during the sweep/flush and cementing process. (Besure that the density of the spacer/pre-flush does not reduce the total hydrostatichead sufficiently to allow a kick to occur.)



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Engineering Recommendations

If the correct pre-emptive actions are taken during each phase of well construction, itis 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 itemisethe properties critical for cementing.

• Include a section in the Mud and Well Programme that will state the opti-mum properties needed for the displacement. Ensure that the 30-minutegel 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 DrillingSuperintendent are all aware of the critical cementing properties duringdrilling.

Drilling Phase

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

• Ensure the reporting process is maintained and those all concerned under-stand the consequences of any slippage from the predetermined proper-ties.

• Establish a contingency plan for the predicted wellbore condition and theprevailing mud properties. If drilling conditions have required the mud prop-erties to deviate from the programme, priorities for the cementing and cas-ing operations may have changed. Discuss the changing situation withthe mud and cement contractor more frequently and establish a new strat-egy for the cementing operations.

Inclusion of the Mud & Cement contractors as early as possible when drilling condi-tions 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 drillingthe last few feet and prior to tripping to run casing?” “Will circulation occur



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

• “Estimate how much time will be needed to condition the mud to optimumproperties for displacement?” “How much time can be spent circulatingwhen 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 ofthe predicted viscosity and density of the mud and the predicted displace-ment conditions. Use all available data to establish if additional condition-ing is required and the pressure profile to be expected during thedisplacement. Use all available Hydraulic Modelling devices with variousscenarios to prepare for all possible mud and wellbore conditions.

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

• Any loss of mud returns that occur during the cementing operations willeffect of the quality of the job. An accurate account of all volumes must bemade at the start of operations, with the anticipated volume gains from thecement and spacers recorded. The anticipated pump rates used to pumpspacers, cement and the displacement must be known by the mud loggersand the mud engineer. The mud engineer and loggers must be given theresponsibility of collecting this data. This information will allow any changestop-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 with-out 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 estimation of the open hole size.

Mass Balance calculations using the retained low gravity solids content, dilution volumesand the efficiency of the solids control equipment can be made to provide accurate information. 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 instability.



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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 con-tamination.

• 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.

• 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 inhydrostatic pressure. Ensure wellbore stability and pore pres-sures remain unaffected by the spacer density or chemistry.

- Spacer viscosity and annular velocities ahead of the cementmay need to be compared with those used during the drilling phase.The hole cleaning performance of the spacer and cement may beimproved to such a degree that cuttings previously undisturbed maybe moved, creating a potential pack-off at any restriction, such asthe liner hanger.

- If the spacer design calls for the use of barite, ensure the initial vis-cosity is sufficient for its suspension.

After tim e and under certa in dow n hole cond itions, the organic m aterial found in W B Mw ill degrade and H 2 S can accum ulate. Pum ping m ud that contains no organic m ateria li.e . Bentonite , barite and w ater, ahead of the cem ent can prevent this problem . H2 S scavengers can be added if required.



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Summary

A great deal of effort will have gone into drilling the hole and the mud will haveplayed a critical role, but this is only its first job. For successful completion of thewell the mud will have to make way for the cement and protect the casing. To con-struct the well, the properties needed for a good cementation must be part of thedaily assessment of mud performance.

The API low and high pressure fluid loss tests performed as part of the mud engi-neer’s tests, will detect variations in the capacity for the mud to seal, but uses alow porosity filter paper, which may or may not reflect the mud’s true sealingcapacity. It is recommended that a Permeability Plugging Test (PPT) be incorpo-rated as part of the mud testing and that an aloxite disk of the required permeabil-ity 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, forachieving good mud properties, for a slurry design with the optimum properties.This section will look at assurance processes and how to engage, not just thecementing contractor, but also others who can make a difference to the successand quality of the job.

The importance of the mud contractor as been repeatedly stressed. Mud, unlikecement, is run as a dynamic, continuously changing process. The properties aremonitored, 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 timeconsuming exercise. Often, it is less than satisfactory on a ‘life of well’ basis.


Cementing Operations Design Process 5-1 Rev. 01/2002

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Everything, therefore, needs to be done to ensure that the first attempt is the verybest possible job. You can’t fix it on the run. The planning has to be of the veryhighest standard.

Traditionally, the cementing service company has supplied the cement,chemicals, pumping equipment and personnel. Their main responsibility used tobe seen as providing the slurry and the capability to pump it into place. Poorquality cement, poor quality additives and a casual approach to lab. testing led to‘train-wreck’ jobs, junked wells and considerable frustration for the operator’sdrillers.

You will have seen throughout this manual the multidisciplinary aspects involvedin getting the best quality job. The best slurry available, with the very best cementand chemicals, will not give good zone isolation across a washed-out hole sectionfull of gelled mud. Nor will an eccentered casing string in a gun-barrel hole, if thespacer and cement are not pumped in an engineered manner which specificallyaddresses the complexity of the fluid rheologies.

Some surprisingly simple steps are often overlooked in the general drillingengineering planning. Sometimes the service company engineer will not give duethought to an aspect of the job because he feels that it is out of his hands. He issometimes encouraged by the drilling engineer into this thinking because he isconcentrating on other aspects of the well. The cementing engineer asks the mudcompany for the mud properties and gets what the mud company thinks theyshould be, rather than what they will actually be. The cementing engineer sees noparticular problem with the mud and, anyway sees his job as getting the slurrydesign and logistics sorted.

On the rig the cementers see their job as mixing the slurry and pumping it withoutmishap. The mud engineer is glad to have reached section TD with the mud insome reasonable shape and is little concerned about the cement job other thanhow it will affect his pit space management. Add to this scenario that nobody hasbeen particularly concerned about centralization and you can find plenty ofreasons why the job is not likely to be a success.


Rev. 01/2002 Cementing Operations Design Process 5-2

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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 plugand 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 forthe 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 drillingteam may not always be those of the field production team. For example, thedrilling team may be happy with cement at TOL and a successful liner lappressure test. The reservoir engineers may be relying on long term isolation ofseveral zones across the liner.

It is now more common to have a multidisciplinary team approach to well planningand a much greater awareness of what the well is trying to achieve – technicallyand commercially. However, it is good practice to spell out just what the objectivesare and make sure that everyone is aware and agrees. Although this may seemobvious, very few cementing programs ever lay out the objectives. It is only ifthese objectives are stipulated that it is possible to judge performance. If you can’tjudge performance, you can’t do much to improve it.



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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 investigationit 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. Theimpossible 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 usedat the Drilling Engineer level to identify and handle risk and its implications for wellcost.

The same sort of approach can be used to ensure that planning for cementingoperations on a well is robust and fit for purpose.

When a cementing service company submits a cementing program to an operatorthis methodology is rarely apparent. Nothing can go wrong. In practice, yourealise there are risks throughout the cementing process – from lab design andtesting, 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 thisis HPHT wells. These wells present extreme difficulties in slurry design anddownhole equipment reliability. Slurry designs can be very sensitive to even minorchanges in additives or procedures. Thickening Times can lurch from excessivelylong to too short just through some seemingly trivial change in some parameter.

If these risks are identified, quantified and the most important ones addressed indetail, then the chances of a successful job are significantly increased. If not, thenthe 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 toachieve sufficient leak-off at the shoe

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

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

• Risk Analysis

Establishes the level of each risk in terms of severity and likelihood. May includemaking 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 ofperformance monitoring and should be preceded by a statement of the objectivesof each cementing job on the well.



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Needless to say, this needs to be a multidisciplinary team approach involving thecontractors (not just the cementing contractor) and the operator.

It can be argued that different types of wells require will require this process to beimplemented with more or less thoroughness, with more or less time andexpertise devoted to it, but all well planning should follow these steps. You wouldnot expect a hospital to undertake an operation without deciding exactly what wasthe aim, how it was to be achieved, what the risks were and how to reduce themto an acceptable level.

Examples

The following are examples of the use of this type of approach. Each drilling teamis likely to do things differently – in some cases maybe not so formallydocumented as in these examples. However, the steps are necessary.

Figure 1: Cementing BoD – offshore, exploration well



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Figure 2: Cementing BoD – onshore well



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An alternative method would be to require the contractor’s Cementing Program tofollow 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 CementingProgram 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 shouldinclude detailed, final recommendations following detailed discussion andanalysis:

• 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 confirm-atory 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-tub-ing

• 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 isa vital element for success. Securing experienced, motivated cementingengineers is increasingly difficult. The format below can be used as a basis forevaluating engineering support proposed by cementing service company. Forcertain types of operation – deepwater, HPHT, ERD – certain additionalexperience may be sought and specified in the assessment form. What isindicated here is just a guide to a more structured approach.



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Figure 3: Example COMPETENCY ASSESSMENT:

ONSHORE CEMENTING ENGINEERING SUPPORT

AreaCompetence / Skill required

Skill - Minimum level required

Assessed Forward Action

Technical Cementing Experi-ence

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 proper-ties and functions of drilling fluids

Completed 1 week basic fluids course.

Overview of Well Construction Pro-cess

Either minimum 5 years off-shore, or 1 week drilling engi-neering course.

Equipment selec-tion and application

Understands principles of opera-tion and limitations of squeeze packers, surface and sub-sea launched plugs, stage collars, centralisers and float equip-ment. Capable of doing all engi-neering calculations related to pressure testing operations.

Slurry Design Aware of all API and BP speci-fied test procedures. Under-stands function and limitations of cement additives. Can deter-mine 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 opti-mum spacer and flow character-istics using a computer simulator.

GENERAL / BP SPECIFIC REQUIRE-MENTS

BP procedures requirements and practices

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



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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.

PERSONAL SKILLS

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

Coaching / Supervi-sory

Can supervise work of junior engineers and be held account-able 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 com-munications skills

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

Commercial Analy-sis

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.



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The aim is to highlight where the candidate is strong and where development isexpected. It is possible that, when the process is complete, it may indicate that acandidate is not suitable. It may indicate that a candidate is able to do the job, butthat training on, and off the job, will be required to enhance performance to thehigh levels required. The selection process for different operations will also takeaccount of the specific technical requirements of the operation.

Process.

Pages 2, 3 and 4 should be completed within the context of the Scope of Workprovided by BP for this service. The scope provides the outline job requirementsfrom BP’s perspective.

When completing the “assessed box”, the competence level should first be deter-mined numerically where;

0 is has no experience in this area.1 is basic only in the assessed area2 is competent in the assessed area3 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 issuggested 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 byre-assessment in 3 months.

Evaluation

As well as good planning and competent people, continuous evaluation ofperformance is essential if improvements are to be made.

There are various ways in which this may approached. One is the end of wellreview 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).



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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 withany commitment.



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Figure 4: Summary

Job element CommentsTraditional Cementing Ser-

vice Company approach

Mud type and properties Mud type will influence the shape and variability of the hole. As the hole becomes less circu-lar, less gauge and less uniform, cementing becomes more diffi-cult.

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 & centralli-sation

Surge pressures need to be min-imised. 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 Engi-neer responsibility. The cement-ing 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 dis-placement mechanics.

Source of revenue.

Mixing and surface equipment hook-up

Optimising this and having con-tingencies 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. How-ever, it is easy to put numbers into software programs and cre-ate a mountain of print-out.

Need to see evidence of optimis-ation of the whole cementing process rather than a hydraulics calculation.

Evaluation, learning & optimisa-tion

Keeping a Basis of Design docu-ment alive through the develop-ment and keeping End of Well reviews up to date so that expe-rience is not solely in the person-nel.

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 cementjob

• 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:

• Cementing Basis Of Design

• Cementing Risk Register

• Cementing Program

• End Of Well Review



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Appendix

Additional InformationPublications

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 centr-alisers (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 Rev. 01/2002

Cement Manual

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, coolingsystem, 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 vis-cous or are heated if needed

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

• Where small quantities of additives are needed, ensure a suitably accurateand calibrated device is available to measure – beware the inaccuratebucket

• If adding to displacement tanks, check that additive concentrations takeaccount of the displacement tanks dead volume

• Check that pressure relief devices have been tested/certified

• Check telephone/tannoy system is acceptable for communication betweencementer 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 alldarts, balls, plugs

• Check cement head (on arrival at the rig site)

- 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?


Rev. 01/2002 Appendix-2

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 removedfrom float equipment prior to make-up

- Check equipment is functional, i.e. ball, flapper or sleeve is in thecorrect 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 & bot-tom plugs. Be absolutely sure.

• Check any bypass baffles and shut-off baffles are compatible with casingand 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 off-shore wells?

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

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

• Is the bottom hole depth & temperature consistent with the lab tests? Lookat any new log data and check against lab test temperature (Bottom HoleStatic Temperature).

Cement Sampling Check List

Particularly offshore, rig-site samples of all materials used in mixing the cementslurry 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 silodetails. Look at additive lot numbers – are they all from one lot? Take anote of the numbers.



Cement Manual

- Has sampling been done correctly?

- Have samples been adequately packaged?

• Cement is a variable product and different batches from the same manu-facturer may give quite different pump times even with the same retarder.Also, cement chemically reacts with any moisture – even moisture in theatmosphere – and the properties (pump time) can change depending onstorage conditions and length of storage. This makes it essential that anycement 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, thenthe 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 containexcess 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 ofthe individual batches or can the cement be homogenized?

Sample Packaging:

• Cement is a very reactive material and will chemically react with moisturein the air. This will change physical properties like thickening time and com-pressive strength development. The extent to which this happens can varywidely. Some cements are particularly sensitive, others not so. In any case,



Cement Manual

small quantities, e.g. a cement sample, are particularly vulnerable to expo-sure and, if not adequately protected, exposure of just a few hours canmake several hours difference to the thickening time – generally lengthen-ing it…. the consequences of testing such a samples and designing theretarder concentration can be disastrous! The following guidelines shouldbe 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, cementtype 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), additivename, lot number, etc

- Note: roll drums, or circulate LAS, to ensure active components ofliquid 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 usesoft drink bottles.



Cement Manual

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 willbe

• Contingencies – blocked cement line, excessive pressure – set maximumpressures 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 oftowards the end of the job

• Do not use a densitometer as the only density measurement. Check peri-odically with a mud balance, preferably a pressurized mud balance.

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

• Keep track of the estimated downhole position of the cement based on thevolume pumped so that any sudden changes in pressure/rate can be inter-preted 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

b.Logistical considerations of rig/location



Cement Manual

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 nitrogenleak

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, densome-ters

c. Equipment maintenance - cementing and nitrogen units, foam generatorassembly,

d 1 inch and

2 inch valves.

e. Data collection during job

1. Pump rates

2. Pressures

3. Nitrogen flow rates



Cement Manual

4 Cross-checks of liquid additive usage (gauging tanks to check liquidadditive 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 (TOTEtanks, 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 - operationallysimpler

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

2. Calculate average foam density in column and check against frac-turing/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 columnlength and fracturing/pore pressure limitations, break job into stages ofconstant gas injection

c. Use the minimum amount of stages possible.



Cement Manual

4. Determine minimum and maximum gas rate for nitrogen pumping unit

a. Determine the maximum LIQUID (base cement slurry) rate possible basedupon nitrogen requirements for foam density and nitrogen pump unit rate limit.

b. Determine the minimum LIQUID rate possible based upon nitrogen require-ments for foam density and nitrogen pump unit minimum rate limit.

c Notify all personnel of this cement rate limit and target cement pump ratefor job at 80-90% of this rate (maximum)

d. Liquid pump rate may be the limiting factor, depending upon cementingunit capability,nitrogen unit capability, and nitrogen requirements. Pleasenote 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 themiddle 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 vis-ual range of each other

b. Nitrogen equipment should be placed, if possible, out of main traffic areason the rig/location

c. Nitrogen lines should be run out of high traffic areas and where the line canbe secured at regular intervals to fixed rig equipment (to prevent lineswhipping 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 can-not 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 equipmentand water should be run on deck to protect steel from cryogenic (-373 F) incase of nitrogen tank leak.

g. Use plastic barrier tape to mark of ‘restricted’ or low traffic areas duringthe 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.



Cement Manual

(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 thecement mixing unit DOES NOT have automatic density control.

c. Averaging/holding tanks recommended for cementing units with mixing tubvolumes less than about 8-10 bbls (even if they have automatic densitycontrol)

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 cementslurry) and cumulative amounts of liquid additives that should be consumedduring the job.

b. Gauge or strap all liquid additive tanks at regular intervals during the joband 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 10bbl/min rates

(upper and lower limits for the table should be the minimum and maximumpump 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



Cement Manual

d. Pressure gauges/transducers

e. Data acquisition devices

13. For automated equipment, have an electronics technician trained for that equip-ment 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.



Cement Manual



Cement Manual

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 Rev. 01/2002

Cement Manual

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 controlPanel

• Be able to mix cement without generating dust beyond that permitted underlegislation

• Designed to minimise risks of trips and falls

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

• For well kill operations and emergency mud circulation the system shall becapable of start up and operations without main platform power for XXhours.

QA/QC Considerations

All materials used in the construction of the unit shall be traceable andmanufacture will be according to ISO9001. All fabricated parts should be shearedor 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 ofdisplacement tanks.

Cement Mixing Performance

Slurry mixing rates to be a minimum of:

• 12 bpm @ 11 ppg

• 6 bpm @ 16 ppg

• 2 bpm @ 22 ppg


Rev. 01/2002 Offshore Platform Cement Unit Specification -14

Cement Manual

Liquid Additive Storage/Proportioning

System to be capable of adding 4 different chemicals and storing a minimum of30 bbls split 15/5/5/5. The system must be able to add chemicals accurately topermit 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 berequired. There should be no shared manifold from the LAP’s to thedisplacement tanks.

Recirculating Mixer

Recirculating mixer should have a total volume of 25 bbl and have agitators suchthat it can be used to batch mix small cement volumes without retaining circulationthrough 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 chemicalsdosed at the displacement tanks. The tanks should be strong enough to carry 22ppg fluids and be constructed to materials suitable for OBM/brines/freshwater/cement spacers/cement chemicals. All sump volumes associated with themixwater 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 beprovided.

Density measurements should be via non radioactive desnsitometers andaccurate 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. Thismust enable 16 ppg slurries to be mixed at > 5 bpm.


Offshore Platform Cement Unit Specification -15 Rev. 01/2002

Cement Manual

Surge Tank

A surge tank is required to provide steady flow to permit mixing at rated definedabove. Contractor is required to advise size of surge tank recommended for thissystem.

High Pressure Manifold

The high pressure manifold shall be configured for dual feed facility of cement tothe drill floor cement manifold. A third line should be “teed” off this manifold androuted 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 notrequire transfer to the steady flow bin or sampling from the bulk tanks.


Rev. 01/2002 Offshore Platform Cement Unit Specification -16

Cement Manual

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 thevolume. If this is not possible use some other method (eg carbide slug). Useexcess cement and circulate excess out if in doubt.

2. Aim for a 250 m plug length, or 20 bbl slurry, whichever is greater volume ofslurry.

Slurry Design

3. Use a heavyweight (17 lb/gal, or more) slurry to get good compressive strengthdevelopment. Use a reliable value of static temperature (BHST) at true verticaldepth (TVD), preferably from log data.

4. Estimate job time accurately, including pauses for switching tanks and plugdropping, then get a Thickening Time with a 1 to 1-1/2 hours' safety factor. UseAPI squeeze schedule values of circulating temperature, based on TVD, with a1 hour initial simulation of batch mixing at 80° F (or surface mix water temper-ature).

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 cen-tralizers.

8. Pump a spacer, weighted half way between mud and slurry density, to fill 300 to500 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 inplace.

Cement Placement

10. Use some sort of bottom barrier for the plug to sit on - either a Viscous Reac-tive Pill ahead of the slurry or a ‘Para-Bow’ device or a weighted slug of heavyviscous mud


Guidelines for Setting Cement Plugs in Horizontal and High Angle Wells -17 Rev. 01/2002

Cement Manual

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 barrierdevice.

13. Use a wiper plug to ensure accurate displacement unless incompatible withbarrier devices in the string.

Job Execution

14. Use a batch mixer to prepare the slurry, checking the density with a pressu-rized mud balance.

15. Pump the spacer round the stinger in turbulent flow unless there is a risk ofexceeding 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 behindthe slurry (accuracy is not too important in a high-angle situation). Weight thisspacer 1 to 2 lb/gal higher than the first spacer to induce cement to fall out ofpipe, 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 andspacer out of the hole.

20. Wait until cement has 3,000 to 5,000 psi compressive strength before taggingand 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 endedpipe (use blanked-off pipe with holes in the side if possible - ie a divertersub)

• Pull out slowly

• Wait long enough before attempting to KO


Rev. 01/2002 Guidelines for Setting Cement Plugs in Horizontal and High Angle Wells -18

Cement Manual

Setting a Kick-off or Abandonment Plug in Open HoleBP Alaskan Guidelines

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

Authority:Drilling Manager

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

Scope:All SSD Operations

Issuing Dept.:Shared Services Drilling(SSD)

Issue Date: February 18, 1999 Revision Date: March, 1999

Control Sta-tus:

Department controlleddocument

CONTENTS REFERENCES

BPX World-wide Plug SettingBHST/BHCT RP


Setting a Kick-off or Abandonment Plug in Open Hole -19 Rev. 01/2002

Cement Manual

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 endeddrillpipe

• 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 expla-nation given.


Rev. 01/2002 Setting a Kick-off or Abandonment Plug in Open Hole -20

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General Pumping Procedure

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

2. RiH with workstring, conditioning the mud and hole until optimal con-ditions 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 dis-placement 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 mini-mum from plug placement.)

Abandonment Requirements

Well abandonment should proceed according to local regulatory requirements andconditions (See Article 2 “Abandonment & Plugging” Section 105 of the Alaska Oiland Gas Conservation Commission). Verify that AOGCC has been contacted forapproval to set an abandonment or kick-off plug.



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 tubingstingers:

Tubing Stinger

Use a tubing stinger on the end of the drillpipe. The length of the stinger should beequal to or greater than the length of the cement with drillpipe in the hole. Thelength of the cement plug, and therefore, the minimum length of a stinger, can becalculated 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 willhelp minimize the disturbance to the cement plug as the drillpipe is pulled up outof the cement, although use of a stinger that is smaller than recommended willresult in annular flow rates that are insufficient for proper plug placement. Cou-pling OD's of the tubing should be minimized. If no smaller tubing is available, 31/2" drillpipe may be considered.

Use the following as a guide.

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. Whenattempting to set a cement plug in open hole where there is no established bot-tom, 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 acement 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 thebottom of the hole and the bottom of the cement plug is another method that willcreate a competent bottom for a cement plug. Use this method if the setting of amechanical bottom is not practical.

Viscous Pill

When neither a mechanical bottom nor a heavy mud spacer can be used, a vis-cous pill may be pumped to provide support for a cement plug. This method is notas reliable as the other two methods but is usually the most practical. The lengthof 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 forviscous 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.)



Cement Manual

Items to bear in mind with Viscous Pills are:

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

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

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

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

• Water based viscous pills must not be used for temporary suspension inOH 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 orwhile being pumped down the drillpipe.

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

Volumes/Excesses

Cement volume is critical to the success of a cement plug. Small cement volumesare consistently lost due to contamination. The minimum length of a cement plugshould be 500’. The maximum length of a cement plug to be set in one stageshould not exceed 1500’. Plug lengths greater than this increase the risk of thecement 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 helpdecide where to set a plug. It is much better to set the plug in a section of the holethat is near gauge.

The actual excess used should take into account knowledge of the particular areaand hole conditions, e.g. sloughing shales or losses.

If no caliper or site specific field data is available , the following excesses are to beused.



Cement Manual

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 iswashed down. Do NOT RIH without pumping.

11c. Repeat steps 5 through 12.

Spacers

Recommended spacer length is 1000’, but maybe less due to hydrostatic con-straints. 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 beadded 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 thespacer 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 1ppg 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.

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



Cement Manual

Wiper Plugs

It is recommended to use a wiper plug to wipe the drillpipe after the workstring hasbeen pulled above the cement plug and the well is being circulated. Running awiper plug between the cement and the spacer is optional, but not mandatory.

Wiper plugs help eliminate cement contamination in the drillpipe and help keepthe cement isolated as it is being pumped down the drillpipe. This is the mostimportant with small cement volumes. This will help to prevent downhole equip-ment 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 cementslurry should be mixed to make up for volume lost due to manifold piping in thebatch mixer. The density should be checked using a pressurized mud balance.

If a Recirculating Cement Mixer (RCM) is used, the cement should be brought upto 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 usedas a batch mixer.

If the cement is mixed using a jet mixer, the cement should be dumped until a con-sistent 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 forkick-off (17 ppg) or abandonment (15.8 ppg). Temperature of the well willdetermine how much retarder will be used to give the required amount ofpump time and set up time.

Fluid loss is only required in plugs set across permeable formations in hole sizesof 8 1/2" or smaller, a fluid loss less than 150 ml is adequate for abandon-ment/suspension. However, less than 75 ml for squeeze slurries (coiled tubing



Cement Manual

slurries are special cases and in house experience should be consulted), is rec-ommended.

Increased thickening times adversely affect compressive strength set times.When kicking off or tagging cement plugs it recommended to wait at least 12 hrsfrom 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 yieldpoint 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 todetermine pump time of slurry. The thickening time test is to be performedat the bottom hole circulating temperature. The results of this test must beobtained 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 adequatestrength for tagging or kicking off from. Perform this test at the bottom holestatic temperature. The results of this test are not required before thecement is to be pumped, although the test should be performed as soon aspossible 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 accu-rately. Reference the BHST/BHCT RP to calculate BHST/BHCT.

Overestimated temperatures are a critical factor in plug failure. Temperaturesshould be included in the written plug procedure to avoid confusion when calculat-ing 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 alsotake into account local experience.

Displacement Rates

Maximum annular velocity is critical to successful plug placement. The minimumannular velocity should be 200 ft/min. These higher velocities will enhance mudremoval and reduce contamination and channelling. In general, the cement plugshould be displaced with the cement unit to ensure accurate control over displace-ment volume. The displacement can be accurately determined using a indicatorsub. When an indicator sub is not used a slight under displacement is desired in



Cement Manual

order to pull a dry string, typically 80’ of the workstring. For plugs deeper than13,000 feet (~4,000m), the average ID of pipe should be determined to ensurecorrect displacement volume.

In the larger hole sections where the cement pump is not sufficient to pump theminimum annular velocity, the slurry may be displaced with either the rig pumps orthe cement unit pump. Rig pumps have a higher capacity, but are substantiallyless accurate than the cement unit pump. If placement is more important thanrate, use the cement unit pump. Conversely, if the rate is more important thanplacement, 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 thechance of obtaining a successful plug.

Pipe movement is one of the most influential factors in mud removal. Reciproca-tion and/or rotation, when feasible, will mechanically break up gelled mud and willgreatly improve flow patterns in the annulus. Move the pipe when conditioning thehole 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 central-ized. After setting the cement plug, pull back at least 300’ above estimated TOCand 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 cleanpipe from cement rings is recommended.

Tagging/Pressure Testing

Plugs should not be tagged until they have at least 1000-psi compressive strengthand 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 compressivestrength.

Compressive strength should be determined at a temperature mid way betweenstatic and the temperature used for designing the pumping time. Where a plug isbeing 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 runback into cement without any circulation.



Cement Manual

Drilling

It should be assumed that the top and bottom 75 feet (~26 m) of a cement plug willbe contaminated with the spacer and appear to be green cement.

If large quantities of cement are observed when circulating well above top ofcement, then it is likely that cement channeling has occurred, with even more con-tamination by the spacer. This will increase the chance of failing to tag the plugand/or obtaining a pressure test.

When kicking off of a cement plug, care should be taken that the entire cementplug is not drilled up. If cement integrity is not there, leave the lower portion of thecement plug in place and place another plug above it using the other plug as abottom.



Cement Manual



F

Q Operational Phase:

See text at:

wwW

Planning 2.1 - 2.3

Ww

Planning 2.2

Hi

Planning 2.3

Wsla

i-Planning 2.4

inal HTHP Guidelines Key

uestion Directed at:

hat experience does the Service Company have locally with HPHT ells? hat experience do the individual engineers have with HPHT?

ServCo Engineer,lab staff, rig site cementers

hat support is going to be brought in to ensure best available expertise ill be available?

ServCo Engineer,lab staff, rig site cementers

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

Lab staff

hat commitment is there from the ServCo to provide a full cementing ervice with positive interaction with other service providers - eg mud,

iner equipment, rig contractor, bulk supplier, etc - to provide more than slurry and a pump?

Drilling Engineer and Serv Co Engneer


See text at:

Wi--

Planning 2.5, 2.10

IH ,

, r,

Planning 2.6

C, ,

Planning 2.6.2

W, ,

Planning 2.6.3


hat are the roles and responsibilities of those who will provide input? Drilling Engineer and Serv Co Engneer, including others, eg mud co.

s the rig equipment good enough and how will this be assured?ow and when will the issues be addressed?

Drilling Engineer, Serv Co Engineerrig site cementersDrilling Contractobulk operator

ement Unit - up to the job? Drilling Engineer, Serv Co Engineerrig site cementers

hat are the limitations imposed by the rig, logistics and weather? Drilling Engineer, Serv Co Engineerrig site cementers


See text at:

Wwtu

i-Planning 2.7, 3.3,

3.6.1

Iacp

i--

Planning 2.8

Hu

Planning 2.4, 2.10

Hp

Planning 2.9, 5.7

Ii

Planning 2.10


hat are the most likely temperatures, how are (were) they obtained, hat confidence can be placed on them, what can be done while drilling

o enhance confidence and reduce uncertainty? Who owns the issue and nderstands it?

Drilling Engineer and Serv Co Engneer

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

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

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

Drilling Engineer

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

Drilling Engineer

s everyone clear what the process is and how it relates to them? Are the nterfaces satisfactory?

Drilling Engineer


See text at:

As

, Planning/execution

3.1, 3.2

A , Execution 2.3, 3.1

C ig Execution 3.2, 5.3

Tki

, Execution 2.7, 3.3, 3.6.1

Hwa

Execution 5.5

C Execution 5.7,

D Execution 5.12

F er

Execution 5.


re there proper prcedures in place for sampling, sample protection and hipment

Serv Co EngineerCompany Rep.

re tests on rig samples consistent with tests on other lab samples. Serv Co EngineerLab Engineer

heck Batch Numbers on all materials Company Rep, Rsite cementers

emperatures - is the circulating temperature(s) consistent with what is nown? What uncertainty is there? To what extent could this affect what

s being done?

Serv Co EngineerLab Engineer

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

Company Rep.

ontingency plans in place? Company Rep.

isplacement volumes, pump efficiencies, volume to bump the plug? Company Rep.

ull, written job procedures? Company Rep., linrunning company,Cement ServCo Engineer

CementManual

Index

General Index

AAdjusting the Slurry Rheology,

3-49Adjusting the Slurry Thickening

Time, 3-49Automatic Sampling, 3-81

BBest Practices, 1-34, 1-75

Centralization, 1-76Displacement Procedures, 1-75Hole Conditioning, 1-75Use of Erodibility Technology,

1-76Use of Plugs, 1-75Use of Spacers, 1-75

Blend Size, 3-69Blending, 3-63

On the Fly, 3-79Blending Equipment, 3-72Blending Procedure, 3-68Bulk Cement Equipment, 2-13Bulk Equipment, 3-71

CCarbon Dioxide, 3-57Casing Centralization, 2-25CemCADE

Cement Job Evaluation, 4-53CBL Adviser, 4-53Plug Cementing, 4-54Post-Job, 4-54Temperature Simulator, 4-54

Centralizer, 4-53Fluid database, 4-52Input data, 4-52Laminar Flow Displacement, 4-53Mud Removal, 4-53

Design, 4-53Evaluation, 4-53

U-tube and placemen, 4-51U-tube and placement, 4-51

Cement, 3-1API Specifications, 3-11

Class A, 3-11Class B, 3-12

Class C, 3-12Class D, 3-13Class E, 3-14Class F, 3-14Class G, 3-15Class H, 3-15

History, 3-10Light Weight, 3-18Limitations, 3-9Other Used, 3-16Pozzolans, 3-16Testing Slurries, 3-19

Dynamic Settling Test, 3-33Fluid Loss, 3-21Free Water, 3-27Gel strength, 3-25Settling Test Tube, 3-32Strength Development, 3-28Thickening Time, 3-19Viscosity, 3-23

Trinity Lite-Wate, 3-18TXI Lightweight, 3-18

Cement Blending, 3-66Cement Heads, 2-15Cement Hydration, 3-6Cement Job Evaluation, 1-71Cement Slurry Design

Important Properties, 3-35Cement Slurry Mixing Water Ratio,

3-35Cementing

Objectives, 1-66Cementing Additives, 3-42Cementing Equipment Selection,

1-33Cementing in Oil Based Mud, 4-63Cementing Program, 1-69Channeling

Minimization, 4-11CMFACTS, 4-59

Features, 4-60CO2 Carbon Dioxide, 3-57Common, 1-49Composite Sample Preparation,

3-83Confirmation Testing, 3-84Controllable Setting Time, 3-37Controlling Slurry Fluid Loss, 3-50Criteria for the Surface Casing,

1-66

DData Collection, 4-50

Density of all Fluids Pumped, 4-50Pump Rate, 4-50Surface Pressure, 4-50

Data from logging tools, 1-77Deep, Long Liners, 3-52Deepwater, 3-59Design Process, 5-1

‘What constitutes success?, 5-3major risks, 5-4What is success?, 5-3

DisplacementJob Simulation, 4-29

Displacement Modeling, 4-29Accurate Geometry, 4-30Fracture Pressure, 4-30Pore Pressure vs. Depth, 4-31Using Simulators, 4-29

Displacements, 4-1Incompatibility, 4-2Problem in a Nutshell, 4-1Rheological Models, 4-5Rheological Properties, 4-5

Dry Blending, 3-75Dry Blending Calculations, 3-70Dry Cement, 3-63Durability, 3-41

EEffect of Magnesium Salt, 3-56Engineering Recommendations

Cementing Phase, 4-70Drilling Phase, 4-69Planning Phase, 4-69Summary, 4-72

Equipment, 2-1Automated Mixing, 2-5Batch Mixing, 2-5Bow Spring, 2-31Casing Centralization, 2-25Cement Heads, 2-15Cement Mixing, 2-1Cumulative volume pumped, 2-10Float Shoes and Collars, 2-18Flow rate, 2-9High Pressure Lines, 2-11


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Cement Manual

Port Collar Operation, 2-23Port collars, 2-22Pressure, 2-9Pumping, 2-6Recording, 2-7Rigid Centalizer, 2-32Safety Considerations, 2-12Slurry Density, 2-8Solid Centalizer, 2-34Stop Collars, 2-49Surface and Subsurface, 2-1Sweges, 2-15Types of Centralizers, 2-31Water Bushings, 2-15Zeroing of the Scale Tank, 3-74

Erodibility, 4-13Definition, 4-16ECD Calculations, 4-20Field Application, 4-17Final Testing, 4-21Wellbore Condition, 4-13

Evaluation of the Recorded Job Data, 1-76

Density record, 1-77Job pressure behavior, 1-77Other problems, 1-77

Extreme Temperatures, 3-52

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

Pre-Flushes, 4-68

GGeothermal Wells, 3-53Granular Materials, 3-51Guidelines for completion of the

assessment, 5-13

HHalliburton, 4-56HPHT, 1-1

IIncrease Slurry Weight, 3-47

Adjusting the Slurry Rheolog,3-49

Barite, 3-48Hematite, 3-47Manganese Oxide, 3-49

Information Transfer, 1-68Interaction with Service

Providers, 1-70Isolation, 2-37

JJob Evaluation

Acoustic Logs, 1-74Temperature Survey, 1-73

Job Simulation, 4-32Example, 4-32Fluid Properties, 4-33Slim Hole Situation, 4-32Wellbore Geometry, 4-32

LLess, 1-59Liner Overlap Seal, 4-47Liner Tiebacks, 4-49Liner Top Packers, 4-44Liquid Blending, 3-71, 3-78Log Interpretation, 1-80

Combination of poor and good bond, 1-81

Continuous good bond, 1-80Continuous poor bond, 1-81Low side/high side, 1-81

Loss Circulation Control Additives, 3-51

MMagnesium Salt, 3-56Major Factors Influencing

Success, 1-25, 1-25API schedules for Thiickening

Time, 1-31Casing Centralization, 1-28Flow Regime, 1-29Mud Condition, 1-26Mud Displacement Practices,

1-25Pipe Movement, 1-27Slurry Design, 1-30Spacers and Flushes, 1-29

Standoff, 1-28Manual Sampling, 3-82Manufacture of Portland Cement,

3-2Mud Conditioning

Different Mud Types, 4-63Engineering Recommendations,

4-69Mud Conditioning and Hole

Monitoring, 4-7Mud Preparation, 4-61MUDPUSH, 4-55

NNo Permeability, 3-38Non-Centralized Pipe, 2-26

OOBM

Drilled Solids, 4-63Low-Shear-Rate Viscosity, 4-63Viscosity, 4-63

OptiCem, 4-56Change in viscosity, 4-58Eccentricity, 4-57Freefall, 4-57Gas, 4-58Mud compressibility, 4-57Temperature dependant

rheology, 4-57Tuned Spacer, 4-57

Overview, 1-1Deep Water, 1-3Estimated job time, 1-20Extended Reach Wells, 1-10Highly Deviated and Horizontal

Wells, 1-7HPHT, 1-1Multilateral Junctions, 1-12Special Considerations, 1-1

PParticles to Lower Slurry

Density, 3-45Hollow Spheres, 3-45Nitrogen - Foam Cements, 3-45

Personnel Competency, 5-11Pilot Testing, 3-63Pipe Movement, 4-27

Highly deviated and Horizontal Holes, 4-28

Liners, 4-28Pore Pressure, 1-35


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CementManual

Portland CementManufacture, 3-2

Post-Job Information, 1-76Cement top, 1-76

Pressure Drop Across Liner Hangers and Polished Bore Receptacles, 4-43

Pressure Recording, 2-9Problems

Annular Pressure, 1-52Cement "Flash Setting", 1-63Failing to Bump the Top Plug, 1-49Flow After Cementing, 1-59Flow Through Unset Cement, 1-60Gas Flow, 1-59Gas Flow Through Microannulus,

1-60Gas Migration, 1-59Lack of Zone Isolation - Cross

Flow, 1-51Liner Tops that Fail Pressure

Tests, 1-57Low Leak-Off Test (LOT), 1-54Low Top-of-Cement, 1-55Soft Kick Off Plugs, 1-55

QQuality Control, 3-63Quality of the Mixing Water, 3-36

Controllable Setting Time, 3-37

RReduce the Risk of Sticking the

Casing, 2-25Reverse Circulating, 4-44

Hole Size, 4-45Job Execution, 4-47Liner Cementing Considerations,

4-45Liner Equipment, 4-47Mud Removal, 4-46Overlap Length, 4-47Temperature, 4-46

Rheological ModelFactors Affecting, 4-6Selecting, 4-6

Rheological Models, 4-5Risk Assessment Process, 5-5Risk Register, 5-8Roles and Responsibilities, 1-65

Planning, 1-66Well design, 1-65

SSafety Considerations, 2-12Salts, 3-54Sampling, 3-63Sampling Liquid Blends, 3-83Sampling of the Blended Cements,

3-81Scale-Down Laboratory Test, 3-61Schlumberger, 4-51Segmented Ultrasonic Tools, 1-79

Quality of the Log Data, 1-80Scanning Ultrasonic Tools, 1-79Tool Selection, 1-79

Settling Test, 3-84Slurry Density, 3-84Slurry Design, 3-35

Density, 3-36Fluidity, 3-37Permeability, 3-38Sufficient Strength, 3-38

Slurry Stability, 3-50Sodium Metasilicate, 3-44Sodium, Potassium, 3-54Soft Kick Off Plugs, 1-55Software, 4-51

BJ, 4-59CemCADE, 4-51CMFACTS, 4-59Halliburton, 4-56OptiCem, 4-56Schlumberger, 4-51

Special Considerations, 1-1HPHT, 1-1

Spiral Flow, 2-39Sulfate Waters, 3-56

TTemperatures, 3-52Thickening Time, 1-32, 3-84

Free Fluid, 1-32Settling Behavior, 1-32WOC Time, 1-33

Thixotropic, 3-58Tools Available

Sonic bond tools, 1-78Ultrasonic Tools, 1-78

UUltralow Temperatures, 3-54Use of Cement by the Oil Industry,

3-42

WWater Concentration, 3-43WBM

Drilled Solids, 4-67Viscosity, 4-67

WellboreBenign hole, 4-38Contamination in the Casing, 4-41Difficult Hole, 4-38Displacement Volumes, 4-42Fluids Left Behind the Casing,

4-41Hole Shape and Pressure Drop,

4-39Job Monitoring, 4-42Narrow Annuli, 4-42Reactive Formations, 4-40Shutdowns, 4-42

Wellbore Condition, 4-38Wellbore Conditioning, 4-61


Rev. 01/2002

BP & Chevron - Cement Manual

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