BP-amp-Chevron-Cement-Manual.pdf

8/20/2019 BP-amp-Chevron-Cement-Manual.pdf

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The

ChevronTexaco and BPCement Manual


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

Table of Contents i Rev. 01/2002

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Knowledge 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Low 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


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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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1

Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Cement Mixing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1Recording . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7High Pressure Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11

Safety Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Bulk Cement Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Cement Heads, Water Bushings, Sweges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15Float Shoes and Collars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Stage Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20

Casing Centralization:

Centralization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25

Reduce the Risk of Sticking the Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25Non Centralization Equals Poor Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27

How 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

What is Cement? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Manufacture 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Cementing 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Aim: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

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

Erodibility Technology:

Wellbore Condition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13

The 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51

Schlumberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51

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

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

BJ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59

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

Mud Preparation and Removal:

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .61Wellbore Conditioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .61

Different 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Aims: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

This 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Guidelines, Check Lists . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

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

Offshore Platform Cement Unit

Specification:

Design Philosophy and Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

HSE Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Guidelines for Setting Cement Plugs in Horizontal and

High Angle Wells:

Plug Setting Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Plug Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Slurry Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Mud Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Cement Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Job Execution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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

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

Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19


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Rev. 01/2002 vi Table of Contents

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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Overview 1-1 Rev. 01/2002

Section 1: Overview

Special Considerations

Introduction

Understand some of the cementing issues presented by:

• HPHT

• Deep Water

• ERD

• Horizontal wells

• Coiled Tubing Jobs

• Multilateral Wells

Examine several special situations which place particular, and often very critical,

demands on the cementing operation, seriously impacting not just the slurry and

spacer systems design, but also the execution of the job, placement equipment

and techniques.

Cementing High Pressure - High Temperature wells (HPHT)

Cementing under conditions of high temperature and/or high pressure is often

required in deep wells and/or wells drilled into environments that present high

temperature gradients. Deep HPHT wells have been drilled in many areas, for

example South Texas, the North Sea and Middle East . Extreme cases of

elevated temperatures include geothermal wells in California and Italy. In other

areas, for instance the Caspian Sea, pore pressures are high requiring very high

drilling fluid and cement slurry densities, but the temperatures are in not extreme.

In any of these applications – high temperature or high density - the cementing

operation requires considerably more attention to detail. The conditions are such

that even minor overlooked details can cause failure. The lower tolerances

associated with HPHT wells are extreme. Under normal well situations the same

details may not present serious problems. Furthermore, the consequences of job


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Rev. 01/2002 Overview 1-2

failure are normally more severe than for ‘normal’ wells. This is due to the

technical difficulties of drilling and completing these wells and the often elevated

costs of such operations.

The best, most experience personnel and resources must be brought to these

wells. ‘Train-wrecks’ in HPHT cementing operations are usually caused by simple

things overlooked or by a complete, total, lack of knowledge about some critical

aspects of the operation (you don't know what you don't know).

Of all the aspects connected with a cementing job, an accurate knowledge of the

well temperatures is normally considered one of the most critical. In HPHT wells,

temperature is, without question, the key to success of the job. Laboratory design

of the cement slurry and spacer systems needs to be done way ahead of the job,

using realistic well temperatures. As drilling continues and better information isobtained, the lab designs need to be refined using exactly the same cement and

batches of additives that will be used on the job.

Another aspect often associated with HPHT wells, is the narrow pore

pressure/fracture gradient window. Accurate knowledge of this is vital for correct

job design. Additionally, realistic simulations of surge and swab pressures to

estimate casing, or liner, running speeds and break circulation are essential.

An HPHT cementing operation should include contingency planning for situationsthat require unexpected cement jobs. For example, sidetracks, losses or casing

shoe squeezes. The slurry and spacer designs need to be tested well ahead of

time. It can easily take a week of laboratory testing to achieve a slurry design

which can be mixed and pumped with confidence at high temperatures.

The best possible quality cement must be used, and the additives must be

selected for the elevated temperatures of the job. Sensitivity testing to

temperature is needed on the critical properties of the cement slurry such as

thickening time, fluid loss, free fluid, rheology and compressive strength

development. This is to cover the uncertainty normally associated with 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 the

design (for example, the need to be able to control gas or water invasion after

cementing). Since elevated temperatures accelerate chemical reactions and

effects considerably, compatibility studies between the drilling fluid, spacer system

and cement slurries must be carefully conducted ahead of time.


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Cementing in Deep Water

Cementing in deepwater presents unique problems to the drilling engineer. Rig

costs are so high, that that the timing of each operation essentially controls thecost of the well. The selection of techniques used to drill the well is driven by the

high cost of time. Thus, reducing that time becomes extremely important.

Likewise, reduction/elimination of failures is essential. For example, it costs

around US $300,000/day for a deepwater rig. If, for example, waiting on cement

time could be reduced for a given operation from say 12 hours to 8 hours, the cost

of drilling the well would be reduced by around $50,000! By the same token,

reduction of failures is of the utmost importance since, again, costs accumulate

rapidly. If it becomes necessary to repair (squeeze) a casing shoe, the cost of that

repair could easily approach or exceed one million dollars.

In deepwater, typically a 30 inch or 36 inch conductor casing is jetted to about 200

ft below the mud line (BML). Next, a 20 inch or 26 inch surface string is cemented

using an inner string method, with the returns being to the ocean floor.

T

Figure 1: Typical Deepwater Shallow Casings Configuration Courtesy 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 parts

of the world, formations shallower than 2,000 ft below mud line can be weak and

unconsolidated. In addition, shallow, highly pressurized, water containing zones

may be encountered. The presence of these shallow, pressurized water zones isquite hard to predict even with the use of shallow seismic methods. These

complex situations, if not handled correctly, can easily lead to the occurrence of

high water flows through the cemented annulus of the shallow surface casing.

Shallow water zones with pore pressures of around 9.5 lb/gal equivalent may

require (depending on the depth where they are encountered), as much as 12 to

14+ lb/gal mud density to control them.

Operators have experienced pore pressures as high as 12.6 lb/gal very close to

the mud line. Very severe water flows have been experienced. It has been

reported that flow rates as high as 30,000 barrels per day are possible in somedeepwater locations. In these extreme situations, the shallow water flow rates

can be so high , that they can generate washout craters large enough to seriously

jeopardize the integrity of the well. There are documented cases in the industry

where uncontrolled shallow flows have practically "swallowed" the entire

multi-well template, at a cost of millions of dollars to the operator.

In addition to the potential for shallow water flows, these deep water wells present

other complicating problems such as:

• shallow gas,

• cool temperature profiles down the riser and at the mud line - oftenapproaching freezing temperature for water,

• narrow window between the pore and fracture pressure,

• large washouts in big holes

• hydrates

To control shallow water flows and the other complicating well conditions, special

techniques and cement slurry designs are used.


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Figure 2: World Areas Experiencing Shallow Water Flows

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 (these

are muds which are lost to the seabed since the riser is not yet connected). The

drilling fluids will have some fluid loss control and tailored rheological properties to

minimize the formation of progressive gels and of thick, mushy mud films across

permeable weak zones. This is done to facility mud removal during the cementing

operation.

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 the

lower critical zones, before pulling the drill pipe. These fluids are designed to

maintain hydraulic control across the water zones, and may include some setting

properties to assist in cementing annular areas that may not be fully covered withcement during the cementing operation. They will not set so well, or as hard, as

cement nevertheless can provide a barrier to flow.

The cement slurries used are specially designed and tested to be able to control

the shallow water zones. Most of the currently used cement systems are foamed.

Foamed slurries can be mixed at different densities using the same base slurry

design. This flexibility is needed to be able to rapidly and easily adjust the slurry

density to the levels needed to control the water zones.

Foamed systems have great sweeping properties to facilitate displacement of themud and/or spot fluid from the large annuli. In addition, they posses the ability to

control water and gas flows by their capacity to maintain elevated pore pressures

in the cement column while it goes through the transition stage. The cement

slurries are often preceded by foamed spacer systems to again aid in displacing

the well fluids.

Shallow gas may also be encountered while drilling the shallow sections of

deepwater wells, but generally is not so problematic as that of the shallow water

zones. In general, the same cement slurry formulations and placementtechniques needed to control the shallow water flows, apply to the control of

shallow gas.

The cool temperatures and the necessarily low cement slurry densities seriously

complicate slurry design. Temperature affects all the properties of cement slurries

that are critical for deepwater cementing: rheology, thickening time, transition

time, free fluid, fluid loss and strength development.

Excessive thickening times are undesirable and the goal must be to eliminate or

minimise WOC time.

Transition Time is the time from when the slurry stops behaving as a fluid (full

transmission of hydrostatic head) to the point when it develops a significant

measurable rigidity. During the transition time of un-foamed slurries, the pressure

exerted by the column decreases due to the generation of progressive gels which

support part of the annular load exerted by the slurry.


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This pressure drop can allow influx of formation fluid or gas into the annulus.

Short transition times are therefore necessary when cementing across shallow

water zones. Again, foamed cement slurries, due to the presence of the Nitrogen

phase, have the ability to maintain the pore pressure of the cement columns,reducing the risk of annular invasion.

Cementing Highly Deviated and Horizontal Wells

Cementing highly deviated wells is somewhat more difficult than vertical, or

near-vertical, wells due to the following factors:

• The casing or liner is difficult to centralise, generally lying on the low side ofthe hole. This makes mud removal difficult.

• Torque and drag considerations can make running a casing or liner to depthdifficult

• Cuttings beds can form during drilling. These may hinder getting the casingto TD. They can also act as a conduit for later flow and compromise zoneisolation.

• Highly deviated wells are often ‘long reach’ or Extended Reach (ERD), thismeans the Equivalent Circulating Density (ECD) can be high. Long sectionlengths create problems with cement channeling past the mud and mixing inthe annulus.

• As deviation increases, wellbore stability problems and the narrowing mudweight window can constrain job design

• Concerns about barite sag can result in relatively higher mud rheologieswhich further constrain the cement placement.

• The cement slurry has to be an extremely stable suspension with very littlefree 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 highly

deviated, 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 below

shows the result of a large scale experiment conducted in a man-made wellbore.

Notice the presence of the solids bed on the low side of the hole. To further

complicate the problem, experiments have shown that solids beds on the low side

of highly deviated and horizontal holes can quickly become immobile (dehydrated)

across permeability, making their removal extremely difficult.


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Research has shown that transport of cuttings in drilling muds becomes more

difficult as hole angle increases. Hard solids beds have also been found on the

low side of the inside of the casing. These ‘inside-casing’ solids beds are not

always easily removed by the cementing plugs; in fact, cementing plugs damage

has been observed in certain cases.

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

Courtesy of Halliburton Services

It can be seen that minimization of solids settling from the drilling fluid while drilling

the hole is critical to the success of the cementation of these types of wells.

Another problem is the tendency of the casing to rest on the low side of the hole.

Across doglegs, the string may even rest against the high side of the well,

depending on the direction of the normal forces generated in the wellbore.

Because of this, to get good cement jobs, it is critical to use proper centralization.

Minimum stand-off should be around 80 to 90% + at the lowest casing point (i.e.

between centralizers). Fortunately, specially designed centralizers have beendeveloped that are capable of reducing drag and torque in these wells, while still

providing good centralization for the pipe. The most recent developments include

rollers to effectively "roll" the pipe to bottom.

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

S t a t i c /D y n a m ic

S o l id s S e t t l in g

•D i ff ic u l t t o

r e m o v e

• S t a t i c /D y n a m i c

S o l id s S e t t l in g

• D i f f ic u l t to

r e m o v e

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


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Settling of solids from the cement slurry and spacer fluids is also a serious

potential problem Therefore, the slurry and spacer used in these wells must be

non-settling statically and dynamically at downhole conditions.

The Free Fluid of the cement slurry must be zero at downhole conditions,

particularly if gas or formation water migration is a potential problem in the well.

An unstable mud or cement can lead to a blow out in these wells.

Estimating well circulating temperatures to design the cement slurries can be a

challenge for these wells. To estimate the well bottom hole circulating temperature

(BHCT), a bottomhole static temperature (BHST) and/or the temperature gradient

in the particular area is used. For vertical holes, the BHCT can be calculated

using API published formulas or temperature charts. While the API method is theaccepted standard for estimating BHCT, the correlations were developed before

deviated drilling was common. Factors such as hole size, pipe size, surface

temperature, water depth (for offshore locations), mud type, pump rates, etc., vary

from well to well and can have an affect on the actual BHCT. Most of the wells

investigated to develop the API temperature correlations were vertical. Thus, for

highly deviated, extended reach and horizontal wells, the API correlations should

not be used.

Other methods to estimate the expected well temperatures are available. 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 and

the other with a horizontal section, the BHCT of the horizontal well will be hotter

due to the high constant temperature along the horizontal section. On the other

hand, if we compare two wells with the same measured depth (MD), one vertical

and one horizontal, the BHCT of the vertical well will be the hotter because it sees

higher temperatures at the bottom of the hole.

One of the best ways of obtaining the BHCT of highly inclined and horizontal wellsis using downhole temperature recorders specially designed for this purpose. One

of the available designs consists of a memory recorder that can be tripped into the

well with pipe or can be dropped down the drillstring during a cleanup trip. The

tool measures the temperature at the bottom of the hole versus time. Once

retrieved, the tool is connected to a portable computer and a graph obtained. This

can be used to estimate BHCT but it should be born in mind that the geometry is


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different. In cementing the annulus is small and the pipe large. When the gauge is

run in DP, the pipe is small and the annulus large. This can result in different flow

regimes and different heat transfer results.

However, with several of these BHCT measurements at different depths in a given

field, a reliable BHCT correlation may be developed. Of course, on critical wells

the cost of making these BHCT measurements may be acceptable; but it is often

critical wells which have high costs and the time is not made available.

Next to actual measurements of the well temperatures, software temperature

simulators can be used to predict BHCT at any well deviation and geometry.

Simulators are capable of estimating the entire temperature profile up and down

the well, not just the BHCT. In long horizontal sections, due to the near constant

temperature, the circulating temperature tend to be near constant too.

The best way to use simulators is to first match measured temperatures from the

well (such as log temperatures). This allows fine-tuning of the simulation to obtain

a more reliable prediction of the BHCT temperature at the depth of interest.

The Measure-While-Drilling (MWD) instrumentation can provide a temperature

while drilling. The BHCT temperature obtained from MWD at the depth of interest

is typically higher than the actual BHCT is during cementing, but it provides an

upper limit to estimate the BHCT for cementing.

Cementing Extended Reach Wells

In recent years, horizontal and extended reach drilling has made possible the

exploitation of many otherwise sub-economic, or inaccessible, hydrocarbon

horizons. Economic considerations have driven operators to continue to "push

the envelope” to reach more hydrocarbon deposits per well, per pad, or per

offshore platform. A major technical obstacle, with ever larger displacement wells,

has been the increasing axial and rotational friction forces generated. Another

complicating factor is the tendency for the pipe to rest on the low side of the hole,making centralization of the casing difficult.


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Courtesy of Weatherford

Figure 4: Extended Reach and Horizontal Well Sections

Bei ru te Bei ru te Co nsultingConsulting

Extended R eachExtended R each

ApplicationsApplicationsExtended

Reach sections Horizontal

well sections


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Extended reach wells, by definition, present long sections of hole where the angle

of inclination is high and essentially constant. These extended sections of hole

can be many thousand of feet. It is not uncommon to find extended reach wells

with measured depths of 15,000 feet or more. These extended sections furthercomplicate problems like formation of solid beds, the difficulty of centralizing the

pipe, etc. All of the comments made in the previous section on cementing highly

deviated and horizontal wells apply to cementing extended reach wells.

An additional factor can be the very high ECD’s which result from the pressure

drop in the annulus in the long hole sections. This can impact displacement rates

which, coupled with eccentric pipe, can lead to massive channeling of cement

through the mud. This again emphasizes the need for a fully integrated approach

to job design. The aims and requirements of the cement job need to be carefully

set out and all the factors which might influence success addressed thoroughly.The mud, the hole condition, the pore/fracture gradient window, dog leg severity

and many other factors will play a crucial role.

Cementing of Multilateral Junctions

Multilateral wells are wells with branches from a main parent wellbore. The

branches are often highly inclined, or horizontal, and multi-directional. When

cementing multilateral junctions, two main aspects need to be considered:

• selection of a cement system that will provide structural support and isolationat the junction.

• the placement technique to displace the drilling fluid and to place thecement/sealant in the well.

Both these aspects create severe difficulties in some types of multilateral well.


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Figure 5: MultilateralWells

For placement of the

cement, industry "best

practices" such as mud

conditioning, centralization,

use of spacer fluids, are all

applicable and should be

used. The selection of the

appropriate cement system

for a multilateral well can be

affected by several factors

specific to these types 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 junctionis placed

• Types of fluids that the cement may be exposed to during the life of the well

Because of the wide variety of requirements that can exist, no one single cement

system is applicable in all cases. Furthermore, in some cases, there is no

currently available cement which will provide the required pressure isolation at the

junction. Thus, the selection of the cementing system needs to be done on a

case-by-case basis.

TAML Multilateral Well Classification

The most commonly used classification of multilateral wells is the TAML

classification.

TAML (TechnologyAdvancement of Multilaterals) is a group of operators with

multilateral experience who developed a categorization system for multilateral

Many multilateral wells are drilled

offshore

Parent well may be a producer in

the conventional way

Multilateral well my be a re-entry

well


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wells based on the amount and type of support provided at the junction. This

categorization makes it easier for operators to recognize and compare the

functionality and risk-to-reward evaluations of one multilateral completion design

to another. Recognized TAML levels increase in complexity from Level 1 (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 cementing

is involved in the construction of Level I.

Level II: Cased Hole Trunk—Open Hole Junction

In these wells the parent well is cased off and cemented, but the laterals are

barefoot (open hole) with or without slotted liners. Level II junctions are also

typically placed in consolidated formations. Again, no cementing is involved in the

construction of Level II multilateral wells in the lateral hole sections. However, the

cement sheath of the parent wellbore need to be considered when choosing a

location for the window for the lateral section.

TAML Multilateral Classification

Level 1Constructiontime: 1 day

Level 2Constructiontime: 2 - 3 days




Level 6Constructiontime: 5 -10 days


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Many conventional cement systems are prone to crack and lose their ability to

provide an annular seal during the process of milling a window, drilling the lateral,

and constructing the junction. For these applications, non-conventional cement

systems are available. For example, research has suggested that foamedcements with gas content between 18 to 38% by volume produce more ductile

systems which are more likely to retain integrity. In laboratory experiments,

foamed cement systems have been shown to withstand significant deformation

and cyclical loading, showing no damage to the integrity of the cement matrix and

experiencing minimal permanent deformation. Cement systems containing latex,

and latex with fibers, have also been used. The primary benefit of the fibers in the

cement is that they hold the cement together even after compressive load failure.

This can help prevent chunks of cement from falling down into the parent wellbore

during milling, drilling, and other operations conducted around the junction.

Level III: Cased Hole Trunk—Mechanically Supported Junction

For these applications, the mother-bore is cased off and cemented. The laterals

are also cased, but not cemented. Level III junctions are again typically placed in

consolidated formations. They have a non-cemented junction with no hydraulic

integrity at the junction. The lateral liner is anchored to the mother-bore. Like

Levels I and II, no cementing is involved in the construction of Level III multilateral

wells in the lateral sections.

Level IV: Cased Hole Trunk—Cased and Cemented Lateral

In Level IV applications, both the main bore and the laterals are cased and

cemented. They include a cemented junction. The junction does not require

hydraulic integrity to be a Level IV junction, but some Level IV systems require

hydraulic sealing at the junction.

In this configuration, the cements used to cement the lateral section must

maintain their integrity under conditions that cements used for conventional jobs

are normally not subjected to. For this junction configuration, a window is milledand a lateral hole drilled. A casing string is cemented through the window to form

the junction. The cement is then exposed to additional stresses when the junction

is completed. For example, the completion process may involve milling off the

casing stub that is left inside the parent wellbore. The milling process leaves a

flush joint at the junction with the cement being exposed to the inside of the casing

at the junction with the main wellbore.


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Some of the physical and mechanical properties that the Level IV junction cement

systems may need to possess include:

• Acid resistance

• Durability to exposure to various oils, synthetic oils, and other fluids

• Impact resistance

• Elasticity

• Hydraulic bonding

Impact resistance will generally be required for every Level IV multilateral junction

system. The cement at the junction will be exposed to impacts during the

completion of the well construction.

Methods used to improve the impact resistance of cements include incorporating

latex in the cement formulation. Foam cements have also been found to improve

a number of the mechanical properties of cement systems.

Conventional cement systems, while having high compressive strengths, are very

brittle and prone to crack when loaded by impacts and/or internal pressure

cycling. For conventional applications, this cracking of the cement may be

acceptable because the cement is not always required to provide hydraulic

sealing from within the casing, nor is the cement exposed to direct impact from

drill pipe, tools, etc. while tripping in and out of the hole. However, for some

multilateral configurations, the cement is relied on to help provide the hydraulic

seal at the junction. Inspection of a model junction will soon indicate that this is

unrealistic.

In addition to the research to help the field engineer with the selection of the "best"

cement systems to use in multilateral applications, work is ongoing to developed

computer modeling capabilities (finite element analysis, etc.) to better predict the

behavior/integrity of cemented sealed junctions when the well is loaded withvarious stress conditions (pressurized junctions, draw-down, etc.) and when

exposed to impact loads.


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One recent, novel technique that needs to be considered for Level IV multilateral

wells involves the treatment of the formation surrounding the formation before or

during the construction of the multilateral hole section with special, low viscosity

resins. For the treatment to work, the formation needs to be permeable to be ableto accept the resin. By injecting the material into the formation, the permeability

can be reduced to essentially zero.

Level V: Cased Hole Trunk—Hydraulically Isolated Junction

In this type of multilateral application, hydraulic integrity at the joint is achieved by

the mechanical completion used and not by the cement. The parent hole is cased

and cemented. The lateral is also cased and cemented. Level V junctions are

placed in consolidated and in unconsolidated formations. They have a cemented

junction, but the cement is not necessarily relied on for hydraulic integrity at the junction. The junction has hydraulic integrity by way of some type of packer

assembly. Level V junctions have main bore and lateral re-entry access.

Level VI: Cased Hole Trunk and Lateral

Level VI junctions are placed in consolidated and unconsolidated formations .

They have a cemented junction, but the cement is not relied on for hydraulic

integrity at the junction. The junction has hydraulic integrity. Level VI junctions

have full bore access to the main bore and the lateral.

Level VIs: Cased Hole Trunk and Lateral & Down-hole Splitter

Level VIs junctions are placed in consolidated and unconsolidated formations.

They have a cemented junction, but the cement is not relied on for hydraulic

integrity at the junction.

Coiled Tubing Cementing

Cementing operations performed with coiled tubing are mostly squeezing andplugging. The most common coiled tubing cementing application is squeezing off

perforations which are no longer required. The well may then be re-perforated

across another zone. Squeezing off perforations which have a high water cut is a

common reason for such intervention.


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Squeeze cementing through coiled tubing (CT) is a relatively new operation in the

petroleum industry. Interest in coiled tubing squeeze operations increased

significantly with the success and cost savings generated in the Prudho Bay field,

Alaska, in the 1980’s. Techniques and cement properties developed or identifiedby BP, ARCO and others for Alaskan North Slope operations served as the

foundation for CT squeeze operations throughout the world.

Squeeze, or remedial, cementing is a common operation in the petroleum industry

throughout the world. Most squeeze operations are conducted with a drilling or

workover rig, through tubing or drill pipe with threaded connections. Cement is

the most common material used for squeezing and represents approximately 7 to

10% of the total cost of the squeeze operation. The rest of the job cost is related

to well preparation, tools, waiting on cement (WOC), drilling out of excess cementleft in the wellbore after the squeeze, etc. Squeeze operations using coiled tubing

offer significant benefits for slurry placement, control of the squeeze process, and

reduced squeeze costs. However, candidate selection and preparation, cement

slurry formulation, and job design require special considerations to realize the full

potential offered by the technique. A serious complicating factor is the reduced

annular clearances often encountered when performing coiled tubing operations.

Using CT can eliminate workover rig costs and significantly reduce well

preparation and post-squeeze cleanup costs. Using CT in workover and squeezeoperations has been successful in remote areas where rigs are not readily

available or in areas where rig costs are high. Bringing a CT Unit to the well,

performing a squeeze, cleaning out and reperforating can make money. Special

techniques and material properties have been developed which improve the

probability of success and realize the cost-saving potential of CT operations.

The process of squeezing with CT is similar in many ways to squeezing through

conventional threaded tubulars. Many of the general techniques for problem

diagnosis, well preparation, and job design and execution used in conventionalsqueeze cementing operations apply to CT operations. However, there are some

differences, and these differences can significantly affect the success of the

operation. CT squeeze operations are essentially scaled-down squeeze

operations: smaller tubulars and annular clearances, and generally smaller

cement volumes. As with most reduced scale operations, attention to details is

very critical in every aspect of the job.


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Coiled tubing lends itself to plugging operations because it allows the operator to

place small volumes of slurry in the wellbore more quickly and inexpensively than

with conventional plugging procedures. Well pressure control can be maintained

at the surface through a stripper and blowout preventer (BOP) so it is possible torun into a live wellbore, and the production tubing and wellheads do not need to

be removed before the job. The tubing can be reciprocated during hole

conditioning.

Temperatures in the wellbore for CT operations can be significantly different from

temperatures in conventional squeeze cementing operations. Downhole

temperatures are affected by many variables including the type of fluid pumped or

circulated, fluid density and rheological properties, volume pumped or circulated,

rate of pumping, and the well configuration. Generally, the temperatures in CT

operations are higher than in conventional squeeze operations with threaded

tubing or drill pipe, primarily because of the lower volumes of fluid pumped and

the lower flow rates used. However, with the larger CT workstrings, the

temperatures may be closer to the conventional case. For most squeeze

operations, and especially CT operations, accurate measurement of the wellbore

temperature and temperature profile above and below the interval to be squeezed

is necessary.

Most cement slurries for conventional applications are tested using well simulation

tests developed by the American Petroleum Institute (API). These tests representa composite set of conditions, generally based on well depth, type of cementing

operation and geothermal gradient. It is important to understand that none of the

current API test schedules or procedures were developed from CT cementing

operations. Therefore, job-tailored test procedures and schedules should be used

to model the planned CT squeeze cementing operation as closely as possible to

field conditions. Job related information needed to formulate job tailored test

schedules include the following:

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

Well pressure (pressure has a lesser effect than temperature on cement hydration

but has a significant effect on fluid loss. Well pressures can be reasonably

estimated from the hydrostatic pressure of wellbore fluids and the cementing

fluids plus the expected surface pump pressure.)


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Mixing equipment and procedure (the amount of time the slurry will be held on the

surface before being pumped into the well can have a substantial effect on the

thickening time of the cement, depending on the surface temperature, well

temperatures and cement slurry formulation.). Batch mixing of the slurry isrecommended, but the type of batch mixer and the way it is operated can affect

the slurry properties. In some cases, particularly relatively small volumes of slurry

(


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The API Operating Fluid Loss test is a filtration procedure performed to determine

the amount of filtrate that can be removed from a slurry under specific conditions.

This test is performed with a known filter medium, under 1,000 psi differential

pressure and at the expected well temperature for the squeeze operation. ForAPI tests, the filter medium is a 325-mesh, stainless steel screen. This screen

has an effective permeability greater than about 1 darcy, and the entire filtration

area is about 3.5 in2.

For most cement slurry designs, the amount of fluid removed from the slurry in 30

minutes under the conditions listed above is the value of interest. However, for

CT squeeze operations, the thickness or volume of filter-cake produced during the

test is also of interest. Pressure applied during a CT squeeze is often higher than

1,000 psi, particularly when excess cement will be washed out to eliminate drilloutcost and time. In these cases, the filter-cake must withstand the pressure

differentials present in the wellbore during cleanout of excess cement before the

cement has hydrated and developed strength. The permeability of the filter

medium used in the API test is significantly higher than many formations,

especially carbonates. In some test cells, core disks or synthetic (aluminum

oxide) disks of varying permeability can be inserted in the cell by using an

adapter. These adapters should be used when available, to better simulate well

conditions during the test.

For CT squeeze simulation tests, filtration time or the time of applied squeeze

pressure usually exceeds the 30 minutes used during an API test. Thus,

filter-cake volume produced under downhole CT conditions can be significantly

larger than the filter-cake volume generated during an API test procedure at a

single pressure. The API fluid loss cell does not have enough volume to

accommodate all the filtrate generated from a CT in-situ test because of the

extended time for squeezing and the higher pressures typically applied during CT

operations. Cement slurries with filtrate volumes in excess of 60 ml will cause all

the slurry to form filter-cake (become dehydrated) in the API cell. Modified

methods for measuring fluid loss and filter-cake have been develop for CT

applications.


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Rheological properties of the cement slurry are more important in CT squeezes

because of the smaller diameter workstrings and slim annular configurations,

placement conditions, and squeeze techniques. Solids suspension, flow

properties, and gel strength development are of primary interest in designingcement slurries for CT squeeze operations.

“Strength of cement” usually refers to the amount of compressive load the cement

will withstand before failure. The compressive strength of a cement slurry can be

determined by the API procedure in which an unconfined 2-in. cube (nominal

dimensions) is compressively loaded (uniaxially) until the cement fails. This

convenient method of compressive strength testing is similar to failure testing

procedures used for construction industry practices from which the API methods

were developed.

The UCA (Ultrasonic Cement Analyzer) has the advantage of providing a

continuous measure of compressive strength vs. time. This compressive strength

is determined from correlations of sonic transit time vs. compressive strength, and

therefore, the results need to be calibrated with destructive API tests. The mode of

cement failure is tensile, or shear which is some 10% or so of the compressive

strength.

The API compressive strength test does not measure the strength of thefilter-cake for squeeze cementing. Cement filter-cake density can be

approximately 18 to 19 lbm/gal for a 15.8 lbm/gal slurry. It has been reported that

some cement blends can build filter-cake compressive strengths of 5,000 psi

before the liquid cement slurry itself has developed any measurable strength.

Under most conditions, the compressive strength of the filter-cake from a squeeze

cementing operation is two to five times greater than the compressive strength of

the un-dehydrated cement.

Durability of the cement is a concern in many CT squeeze operations. Portlandcements are subject to attack by a variety of well fluids such as acid, certain

components in formation waters, carbon dioxide, and others. To increase cement

resistance to acid and some brines, latex has been used in the formation. Fly ash

has been used to improve cement resistance to carbon dioxide.


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Regarding placement of the cement slurry, where possible, spotting cement

across the interval to be squeezed is preferred. The general procedure

recommended for spotting cement with coil tubing is listed below. This technique

is designed to minimize contamination of the cement with the fluid in the wellbore.1. RIH to TD or below the squeeze interval.

2. Begin pumping cement out the CT.

3. Allow the top of the cement to rise above the nozzle at the end of the 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 1-25 Rev. 01/2002

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 to

create the open hole must be removed from the annulus ahead of the cementslurry. Most investigators agree that the following factors affect the process of

mud displacement:

• Mud properties to drill the hole, and mud conditioning prior to the cement job

• Hole condition - non uniform, washed out hole presents special difficulties

• Pipe movement - rotation or reciprocation

• Pipe centralization

• Fluid velocity - pump rate

• Mud filter cake condition (erodibility)

• Spacers and flushes

• Cement slurry poperties


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

Mud Condition and Mud Conditioning

Perhaps the most critical of the displacement factors is the condition of the hole

and the mud prior to cementing – in fact, prior to picking up pipe.

During hole conditioning, it is necessary to create a situation where the bulk of the

mud is moving (circulating). Therefore, the goal of the conditioning process is to

end-up with a “high mobility mud” across the entire annular length and

cross-section. To achieve this, it is necessary, once the casing gets to bottom, to

break and circulate all the pockets of gelled mud before the initiation of mixing and

pumping of the cement slurry.

For deviated wells, the low end rheologies (and gels) of the drilling fluid are

normally higher than for vertical wells. The higher properties are needed to

minimize solids settling from the mud on the low side of the hole while drilling 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 (see

Figur), particularly across good permeability.

Courtesy of Halliburton Services

Figure 7: Solids Settling from Drilling Muds in Deviated Wells. A large ScaleExperiment

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 go

well. However, as confirmed by large-scale experiments, if permeable zones are

drilled with mud with poor properties (capable of developing thick, gelled, partially

dehydrated, mud cake), it is extremely difficult to get the bulk of the mud in the

annulus moving. In fact, there is evidence that pumping a high mobility


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(conditioned) mud in the hole during hole conditioning in this situation, may lead to

channeling of the high mobility mud through the low mobility (gelled) mud. At the

surface, the mud properties may look fine, giving a false indication that the hole is

in good shape. In such a situation, the chances of getting a good cement job are

reduced greatly. The answer is to ensure the zones of interest (pay) are never

contacted by a low quality drilling fluid. The pay zones need to be drilled with a

high mobility, good property drill-in mud that can be easily conditioned before the

cement job.

Pipe Movement

A fairly straightforward and relatively simple technique to aid in the mud

displacement process is to move the pipe while conditioning mud and, if possible,

while pumping the cement into the annulus. Full-scale displacement tests have

shown that simple pipe movement, either rotation or reciprocation, can improve

displacement. Pipe movement helps remove gelled mud and assists in getting a

competent, uniform sheath of cement all around the casing.

• Pipe movement is often not a viable option in the following circumstances:

• large ‘surface’ casing strings (bigger than 9 5/8”)

• very long strings

• high deviation wells or wells with high doglegs (DLS)

• offshore wells fromdrillships or semi-submersibles.

In near-vertical wells, during reciprocation the pipe tends to move from side to

side of the hole and this helps break much of the gelled mud. For highly deviated

and horizontal wells, the pipe may not move from side to side so well (around

doglegs, for example).

With reciprocation in highly deviated/horizontal holes, the pipe may get stuck on

the upward stroke, potentially leaving uncased openhole. Reciprocation

sometimes limits pipe movement to only pre-cement job conditions. In deviated

wells, rotation has an advantage over reciprocation in that it tends to drag thefluids all the way around the pipe (better mud removal).

With liners, reciprocation all the way to bumping of the plug has been used very

effectively in near-vertical holes. Reciprocation is much better than no pipe

movement, but regardless of deviation, with liners, rotation is preferred because it

overcomes some disadvantages of reciprocation:


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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 tothe desired setting depth.

• It is less risky when the drillpipe and setting tool can be released from theliner prior to cementing.

The best practice is to begin casing movement as soon as the liner reaches

bottom and continue during hole conditioning and until cementing is finished.

Rotation should be at least 10 to 20 rpm.

Casing Centralization

A well planned and executed centralizer program is one of the items on the “must

do” list to obtain a good primary cement job, particularly in highly deviated wells.

Displacement of the mud on the narrow side of the annulus will not take place if

the pipe is close to, or against, the wellbore wall.

Adequate centralization of the casing is essential to obtaining good displacement

of the drilling fluid and proper placement of the cement slurry around the pipe.

Whilst pipe centralization is sometimes – incorrectly - viewed as optional for

vertical wells, it is a requirement for cementing under deviated conditions. If thepipe is not mechanically centralized, the pipe will lay on the low side, making it

impossible to obtain a cement sheath that completely encircles the casing.

Centralization of the casing helps provide a uniform flow path around the entire

circumference of the casing so that the mud can be more readily replaced.

Large-scale tests have shown that mud displacement efficiency is directly related

to the degree of casing centralization.

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

A well designed and executed casing centralization program will also greatly

assist in running the casing to bottom, and with moving of the pipe once on

bottom. Special centralizers have been developed recently that reduce torque

and drag during running and moving of the pipe. The type and number of

centralizers, and their location on the pipe, needs to be optimized using industry

available computer programs, particularly for highly deviated wells.


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Fluid Velocity - Pump Rate/Flow Regime

The velocity (rate) at which the various fluids are pumped during the conditioning

of the drilling fluid and during the actual cement job is a major factor in achieving a

good mud displacement and cement job.

Oil industry experts agree as to the benefits of pumping fluids in turbulent flow.

However, because of the viscous nature of most cement slurries, it is usually

difficult to achieve turbulent flow without breaking down weak formations in open

hole. If this is the case, cement slurries will be pumped in laminar flow.

Extensive studies of the effects of fluid velocity (flow regime) have been made

both in full-scale displacement studies and in actual wells. The majority of the

results from the full-scale displacement studies have shown that the faster flow

rates will provide better displacement efficiency. These results have been

confirmed in actual field jobs where the percent open hole volume circulating was

measured as a function of flow rate.

It is now known that the higher flow rates provide better displacement efficiencies

because higher flow rates generate higher shear forces in the open hole. The

higher the shear forces (shear stress) on the hole, the more partially

dehydrated-gelled (PDG) drilling fluid will be broken free and circulated from the

annulus.

Spacers and Flushes

Spacers and Flushes are used ahead of the cement slurry to prevent mud

contamination of the cement slurry (formation of thick masses), and to facilitate

the removal of the drilling fluid. However, spacers are very difficult systems to

optimize.

Spacers must be compatible with two fluids, the mud and the cement slurry. In

general, these are very incompatible with each other. Spacers are designed to“work chemically” with muds and cement slurries. Since every mud and cement

slurry is different, spacers should be essentially “custom designed” for every job.

It should not be assumed that a spacer formulation which worked with a previous

field mud will also work with the present field mud, even if similar additives are

being used. This is particularly important when designing spacers for oil-based

mud systems.


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When designing or evaluating a spacer system, the following criteria should be

used to maximize the spacer’s effectiveness downhole:

• The spacer must be compatible with both the drilling mud and the cementslurry.

• The spacer must be non-settling.

• The spacer should have a density between that of the drilling mud and thecement slurry, when possible, to assist with mud displacement and to reducechances of channeling.

• If possible, the spacer should have a consistency between that of the drillingmud and the cement slurry to again help with mud removal.

• When using oil-based muds, the spacer must contain surfactants forwater-wetting the pipe and formation face, to enable the cement to bondeffectively 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 openhole

• Based on field experience, enough spacer volume should be pumped toachieve a minimum of 10 min contact time at the top of the pay, or to fill 800to 1,000 ft of annulus, whichever produces the greater volume.

• The spacer should possess fluid loss control.

Cement Slurry Design Considerations

The cement slurry design for a given job needs to be specifically tailored to the

particular requirements for the given section of hole to be cemented. Of the

utmost importance is keeping the design simple; including only essential

additives. If ‘book’ formulations from previous jobs are considered, they need to

be very carefully re-examined to ensure they apply to the specific well conditions

at hand.

The cement, additives and field mixing water used in the laboratory to optimize

the slurry design must be the same as to be used on the job (same batches).

Cement quality is very important. A quality, consistent, API monogrammed

cement should be used whenever possible. However, lower quality cements are

sometimes used due to remote location and other factors including local

government requirements. In those cases, laboratory testing needs to be even

more rigorous. For example, sensitivity tests of the slurry design to temperature


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should be performed, since the well temperatures that the slurry will see are not

well known (margin of error is often +/- 10 to 15 degrees F for the BHCT).

Properties that Need to be Measured for Slurry Designs

To minimize the potential for job failures, the following properties should to 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 will

remain pumpable at bottom hole circulating temperature and pressure. The API

thickening time test schedules are “standard” based on generalized well designs

(casing sizes, casing depths, pump rates, well pressures), and should be used

only for preliminary designs, before details for the particular job are known. Once

the details for the job are available: casing size, depth and mud density, as well asthe projected pump rate, these parameters need to be used to calculate a

job-tailored test schedule. With this approach, time to BHCT and maximum job

pressure often differ from standard API Schedules. This difference between the

“job-tailored” and the API Schedules may have a marked effect on the measured

TTs for the slurries.


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Acceptable Values for Thickening Time:

A criteria for acceptable thickening time values is needed, to minimize WOC times

and the time cement slurry remains liquid after placement. A criteria often used is:

Minimum TT = MEPT + 1 hour ( 2 for some jobs, 1/2 hr for plug jobs)

Where:

MEPT = Maximum Estimated Job Placement Time

TT = Thickening Time

If the cement slurry will be batch-mixed, the surface retention time (time in the

batch mixer) needs to be added to the calculated minimum TT, but must be

simulated in the laboratory at the expected surface mixing temperature and

atmospheric pressure.

Maximum TT acceptable is normally two to three hours above the Minimum TT.Longer maximum TTs may be acceptable provided compressive strength at the

top of the cement column is developed within field acceptable WOC times.

Free Fluid

Free fluid is an important cement slurry property related to slurry stability. It

should be measured as closely as possible to downhole conditions. The preferred

value for free fluid is zero, particularly for highly deviated wells, and particularly if

gas/brine migration after cementing is a risk. For nearly vertical holes, the

maximum allowed free fluid should be around 1.0%, provided gas/brine migration

is not a concern.

Cement Slurry and Spacer Fluid Settling Behavior

A very critical property of the cement slurry is its solids suspending ability, both

during and after placement, particularly for highly deviated and horizontal wells.

In these wells, solids in suspension have a much shorter settling path than they

would in a vertical well. Because solids can settle out of a slurry while being

pumped the cement slurry must have sufficient yield point at downhole conditionsto prevent dynamic settling. After placement, the slurry must suspend the solids

until it develops sufficient gel strength to support them while setting.

The same comments regarding solids suspension apply to spacer fluids. For

example, the spacer needs to suspend its solids statically to keep from grabbing

drillpipe during liner cementing.


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WOC Time

The waiting on cement (WOC) time is best determined using an Ultrasonic

Cement Analyzer (UCA). The UCA provides a nondestructive way to continuously

monitor compressive strength development under downhole temperature andpressure.

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

cement column.

The cement slurry should be pre-conditioned in a consistometer. The preferred

practice is to run UCA compressive strength tests at both bottom hole and at the

top of the cement column or top-of-liner conditions to determine the optimum time

to resume operations in the well. Normally, operations should not be resumeduntil the cement has developed 500+ psi at the top of the column. It needs to be

remembered that the UCA obtains the compressive strength from correlations

based on the acoustic transit time of the cement. Often, it is found that the

compressive strength estimates of the UCA are conservative when compared with

destructive (crushed) compressive strength tests. However, the UCA estimate of

the time for initial set (~50 psi strength) is often quite accurate.

Cementing Equipment Selection

One of the important functions of the operating company engineer is to liaise with

the service company to make sure that job

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