Work Over Well Control

Well Control for Workover Operations

While every effort was made to ensure accuracy, this manual is intended only as a training aid. Nothing in it should be construed as approval or disapproval of any specific product or practice. Furthermore, Schlumberger assumes no liability with respect to the use of any information, apparatus, method, or process in this manual. This manual was developed by Schlumberger in conjunction with Randy Smith Training Solutions. The manual remains the property of Schlumberger and is not to be copied, modified, or reproduced without the express written consent of Schlumberger. It is intended for internal use only. All rights reserved.

Well Control for Workover Operations

Contents List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi 1. Introduction to Workovers . . . . . . . . . . . . . . . . . . . . . . . 1-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 Reasons for Workovers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-3 Types of Workovers and Associated Well Control Equipment . . . . . . . . . 1-13

2. Well Control Principles and Calculations . . . . . . . . . . . 2-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2 Overview of Workover Well Control Calculations . . . . . . . . . . . . . . . . . . . 2-2 Calculations Related to Well and Formation Pressure . . . . . . . . . . . . . . . . . 2-7 Calculations Related to Well and Workover Fluid Volumes . . . . . . . . . . . 2-19 Forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-37 The Barrier Concept . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-40 Gas Behavior in the Wellbore. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-41

3. Well Control Procedures. . . . . . . . . . . . . . . . . . . . . . . . . 3-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 Recording Slow Circulating Rate Pressure. . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 Shut-in Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4 Circulating Well Control Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10 Noncirculating Well Control Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . 3-28 Selection of Well-Kill Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-47

4. Causes and Warning Signs of Kicks . . . . . . . . . . . . . . . 4-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 i

Causes of Kicks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 Warning Signs of Kicks and First Actions . . . . . . . . . . . . . . . . . . . . . . . . . . 4-6

5. Completion and Workover Fluids . . . . . . . . . . . . . . . . . 5-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 Types of Workover and Completion Fluids . . . . . . . . . . . . . . . . . . . . . . . . . 5-2 Functions of Completion and Workover Fluids . . . . . . . . . . . . . . . . . . . . . . 5-2 Completion and Workover Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . 5-4 Components of Completion and Workover Fluids . . . . . . . . . . . . . . . . . . . . 5-9 Supervisor’s Roles in Maintaining Properties . . . . . . . . . . . . . . . . . . . . . . 5-16 Displacing to Drilling Muds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-25

6. Surface and Subsurface Equipment . . . . . . . . . . . . . . . 6-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Typical Completions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 Completion String Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 Wellhead and Christmas Tree. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-19 Surface Safety Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-21 BOP Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-27 BOP Equipment Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-49 Vacuum Degasser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-55 Echometer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-56

7. Well Control Complications . . . . . . . . . . . . . . . . . . . . . . 7-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Holes in Tubing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-2 Tubing-to-Casing Communication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 Surface Pressure Stabilization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-13 Reversing Gas Kicks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-15 Problems While Circulating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-21 Unexpected Changes in Gauge Readings . . . . . . . . . . . . . . . . . . . . . . . . . . 7-22 Trapped Pressure below Packers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-23 Use of Work-String Check Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-23

ii

Well Control for Workover Operations

8. WSS Roles and Responsibilities . . . . . . . . . . . . . . . . . . 8-1 Lesson Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 Lesson Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 Planning and Preparation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-2 Workover Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-11 Well Control Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-14 Sample Workover Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-16

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .G-1 Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 A. Abbreviations for Chemical Compounds . . . . . . . . . . . . . . . . . . . . . . . . A-1 B. Summary of Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2 C. Increasing Density in Multiple-Salt Brines . . . . . . . . . . . . . . . . . . . . . . . A-8 D. Conversion Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-10 E. Brine Filtration Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-13 F. IPM Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-14 G. Well Control Worksheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-16

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1

iii

iv

Well Control for Workover Operations

List of Figures 1-1. Gravel packing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-5 1-2. Excessive gas production in oil wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-6 1-3. Water coning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7 1-4. Recompletion to a higher zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-8 1-5. Recompletion to a lower zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-8 1-6. Zonal isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9 1-7. Conventional workover rig and equipment . . . . . . . . . . . . . . . . . . . . . . . . 1-14 1-8. Concentric workover using coiled tubing unit . . . . . . . . . . . . . . . . . . . . . . 1-15 1-9. Wireline workover equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-16 1-10. Pump unit and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-17 2-1. Overview of workover well control calculations and indicators . . . . . . . . . 2-3 2-2. SICP and SITP gauges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-4 2-3. Tubing/annulus friction pressure distribution. . . . . . . . . . . . . . . . . . . . . . . . 2-6 2-4. True vertical depth (TVD) and measured depth (MD). . . . . . . . . . . . . . . . . 2-8 2-5. Calculating kill fluid weight (balanced and overbalanced) . . . . . . . . . . . . 2-15 2-6. Sample conditions for static well analysis . . . . . . . . . . . . . . . . . . . . . . . . . 2-17 2-7. Determining tubing or casing capacity factor and volumes . . . . . . . . . . . . 2-20 2-8. Determining annular capacity factor and annular volume . . . . . . . . . . . . . 2-21 2-9. Determining displacement factor and displacement volumes . . . . . . . . . . 2-23 2-10. Conditions for determining circulating bottomhole pressure . . . . . . . . . . 2-35 2-11. Determining cross-sectional area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-37 2-12. Determining pressure force on a cross-sectional area . . . . . . . . . . . . . . . 2-38 2-13. Differential force . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-39 2-14. Gas expansion according to the gas law. . . . . . . . . . . . . . . . . . . . . . . . . . 2-42 2-15. Effect of gas migration on bottomhole pressure. . . . . . . . . . . . . . . . . . . . 2-44 3-1. Pressure profile during bleeding with mechanically induced kick. . . . . . . . 3-8 3-2. Pressure profile during bleeding with light fluid in the hole . . . . . . . . . . . . 3-9 3-3. BPV or check valve in string . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10 3-4. Pressure profile for wait-and-weight method . . . . . . . . . . . . . . . . . . . . . . . 3-13 3-5. Five steps for completing pressure reduction schedule . . . . . . . . . . . . . . . 3-14 3-6. Well with 10 bbl kick . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-16 3-7. Circulating pump pressure schedule. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-17 3-8. Pressure profiles for constant pump pressure method . . . . . . . . . . . . . . . . 3-19 3-9. Well diagram with gas kick . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-21 3-10. Reversing a gas kick: stage 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-22 3-11. Reversing a gas kick: stage 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-23 3-12. Reversing a gas kick: stage 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-24 3-13. Reversing a gas kick: stage 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-25

v

3-14. Reversing a gas kick: stage 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-26 3-15. Pressure profiles for reversing a gas kick. . . . . . . . . . . . . . . . . . . . . . . . . 3-27 3-16. Bullheading. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-29 3-17. Bullheading pressure profile. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-32 3-18. Bullheading pressure schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-34 3-19. Plotted bullheading pressure schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-35 3-20. Casing pressure increase during bullheading . . . . . . . . . . . . . . . . . . . . . . 3-37 3-21. Gas channeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-38 3-22. Volumetric calculations and pressure schedule . . . . . . . . . . . . . . . . . . . . 3-41 3-23. Well diagram for volume method. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-44 3-24. Sample well and volume method lubrication worksheet . . . . . . . . . . . . . 3-45 3-25. Well diagram and pressure method lubrication worksheet . . . . . . . . . . . 3-46 4-1. Sample trip sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7 5-1. Brine density thermal correction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 5-2. Hydrometer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-7 5-3. Increasing density in solids-laden fluids . . . . . . . . . . . . . . . . . . . . . . . . . . 5-18 5-4. Decreasing density of solids-laden fluids. . . . . . . . . . . . . . . . . . . . . . . . . . 5-19 5-5. Increasing density in single-salt brines. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-20 5-6. Decreasing density by dilution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-21 5-7. Temperature correction with a hydrometer . . . . . . . . . . . . . . . . . . . . . . . . 5-23 6-1. Open-ended completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 6-2. Basic single-zone packer completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 6-3. Packer completion with nipples, sliding sleeve, and SCSSSV. . . . . . . . . . . 6-3 6-4. Multiple-zone, multiple-string completion. . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 6-5. Sand-control completion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 6-6. Artificial-lift completion—rod-pumped . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5 6-7. Artificial-lift completion—gas-lift . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-6 6-8. Artificial-lift completion—electric submersible pump (ESP) . . . . . . . . . . . 6-7 6-9. Retrievable packers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-10 6-10. Permanent packers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-11 6-11. Typical tubing hangers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-12 6-12. Bridge plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-13 6-13. Typical landing nipples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-15 6-14. Flow-control device locked into a selective landing nipple . . . . . . . . . . . 6-16 6-15. Surface-controlled subsurface safety valve (SCSSSV) . . . . . . . . . . . . . . 6-18 6-16. Typical wellhead and Christmas tree . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-19 6-17. Wireline surface rig-up. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-21 6-18. Typical surface safety system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-22 6-19. Pneumatic surface safety valve and operation . . . . . . . . . . . . . . . . . . . . . 6-23 6-20. Low-pressure fusible plugs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-24 6-21. High-pressure fusible plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-24 vi

Well Control for Workover Operations

6-22. Wireline-cutting operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-25 6-23. Typical wireline-cutting surface safety valve. . . . . . . . . . . . . . . . . . . . . . 6-26 6-24. Typical tree gate valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-27 6-25. Commonly used annular preventers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-28 6-26. Typical ram preventer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-31 6-27. Types of ram blocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-32 6-28. Commonly used ram preventers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-33 6-29. Full-opening safety valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-36 6-30. Gray IBOP (“Gray valve”) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-37 6-31. Drop-in check valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-38 6-32. Wireline-set blanking plug . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-39 6-33. Typical manual and remote chokes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-40 6-34. Example of control panel for remote choke . . . . . . . . . . . . . . . . . . . . . . . 6-41 6-35. Positive and adjustable production chokes. . . . . . . . . . . . . . . . . . . . . . . . 6-42 6-36. Hydraulic control unit (“closing unit”). . . . . . . . . . . . . . . . . . . . . . . . . . . 6-43 6-37. Data needed for calculating useable accumulator volume—BOP stack . 6-44 6-38. Data for calculating useable accumulator volume—closing unit. . . . . . . 6-45 6-39. Data for calculating useable accumulator volume—open/close volumes 6-45 6-40. Calculations for useable volume. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-47 6-41. BOP control panel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-48 6-42. Back-pressure valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-49 6-43. Vacuum degasser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-55 6-44. Degassing operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-56 6-45. Typical echometer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-57 7-1. Collar stop running tool and ponytail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-3 7-2. Pack-off assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 7-3. Shifting sliding sleeve to open position . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-6 7-4. Side-pocket mandrel with gas-lift dummy or valve . . . . . . . . . . . . . . . . . . . 7-7 7-5. Extracting dummy valve from side-pocket mandrel . . . . . . . . . . . . . . . . . . 7-8 7-6. Perforating the tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-9 7-7. Information needed to determine tubing-to-casing differential . . . . . . . . . 7-11 7-8. Calculations for determining tubing-to-casing differential pressure . . . . . 7-12 7-9. Effect of settled salt and U-tube flow on tubing-to-casing communication 7-14 7-10. Types of backup safety valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-16 7-11. Leak points on typical chicksan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-17 7-12. Choke responses required in reversing gas kick. . . . . . . . . . . . . . . . . . . . 7-19 7-13. Atmospheric degasser. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-20 8-1. Schematic for sample workover procedure (present completion) . . . . . . . 8-20 8-2. Schematic for sample workover procedure (proposed completion). . . . . . 8-21

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Well Control for Workover Operations

List of Tables 3-1. Typical Kill Rate Pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4 5-1. Densities of Typical Completion/Workover Fluids . . . . . . . . . . . . . . . . . . . 5-5 5-2. Common Additives and Their Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-11 5-3. Densities of Some Commercially Available Brines . . . . . . . . . . . . . . . . . 5-12 5-4. Composition and Properties of Sodium Chloride Brine . . . . . . . . . . . . . . 5-14 5-5. Composition and Properties of Potassium Chloride Brine . . . . . . . . . . . . 5-15 5-6. Mixing 2% Potassium Chloride Solution . . . . . . . . . . . . . . . . . . . . . . . . . 5-15 5-7. Composition and Properties of Calcium Chloride Brine . . . . . . . . . . . . . . 5-16 6-1. Packoff Elements for Annular Preventers . . . . . . . . . . . . . . . . . . . . . . . . . 6-30 6-2. Typical Ram Preventers Used in Workovers . . . . . . . . . . . . . . . . . . . . . . . 6-34 A-1. Mixing CaBr2/CaCl2 Brine .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-9

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Well Control for Workover Operations

Preface Written specifically for the well-site supervisor, Well Control for Workover Operations presents the concepts, procedures, and practices that apply to well control for workover operations. This text, along with an associated workbook and a Web-based final exam, comprises an entire self-study course in workover well control, designed for learning without an instructor. For the benefit of those with limited experience in workovers, the book begins with an overview of what workovers are, why they are done, and how they are categorized by type. The next lesson covers basic well control physical principles and calculations, illustrated with detailed examples. Well control procedures are presented next, followed by the causes and warning signs of kicks. Emphasis is placed on the well kill procedures typically implemented at the start of a workover and the techniques used to prevent further kicks during the actual workover operation. Following kick prevention are lessons on workover fluids and surface and downhole equipment. The lesson entitled “Well Control Complications” explains methods for dealing with complications that are sometimes encountered in workover well control. The final lesson covers all aspects of your responsibilities in supervising the workover—from well control planning and preparation to execution. The associated workbook contains review questions for each of the eight lessons. It is suggested that you read one lesson and then go to the workbook and answer the related questions for that lesson before reading further. The entire process can be completed in about five days. After working through all the lessons, you should access and complete the final exam on the Schlumberger Hub. In addition to the lessons, you will find the book’s appendix useful; it contains a list of calculations, a list of chemical name abbreviations, and a metric conversion table. A glossary of terms provides definitions for the technical terms used in the book. In specific areas where specialist applications have been used and the general rig ups, arrangements, and guidelines do not follow the contents of this manual, or where exemptions to the standards have been required, the operational procedures for that area must be detailed in the Project Operations Manual for that particular project.

Preface

xi

This manual forms part of a series of training texts for well control within Schlumberger. Further information, documents, reports, guidelines, and standards can be found at one of the following Schlumberger Hub locations: http://www.hub.slb.com/index.cfm?id=id15751 InTouch reference page -Well Control in OFS (#3322918)

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Well Control for Workover Operations

1 INTRODUCTION TO WORKOVERS Lesson Overview After a well is drilled to total depth, the production casing and wellhead are set, cemented, and pressure tested. Any subsequent operations are referred to as completion operations. Well completion includes such work as installing a system of tubulars, packers, and other tools beneath the wellhead in the production casing to provide a path for the oil or gas to flow to the surface. The completion allows the operator to extract and regulate the well fluids as efficiently as possible. Over time, however, changes occur in the formation, and the completion equipment itself deteriorates; it becomes necessary to service the well or to work over the well to maintain or improve efficient fluid flow. The term workover refers to a variety of remedial operations performed on a well to maintain, restore, or improve productivity. Workover operations can include such jobs as replacing damaged tubing, recompleting to a higher zone, acidizing nearwellbore damage, plugging and abandoning a zone, etc. The term well servicing refers to workover operations performed through the Christmas tree with the production tubing in place. This operation is also known as “well intervention.” Coiled tubing, small-diameter tubing, wireline, and snubbing work strings can be used. Many of the operations are similar to those in workovers but are constrained by the internal diameter (ID) of the existing completion. Although this manual focuses on workover well control operations, the workover wellsite supervisor (WSS) will benefit from background information on the reasons for and different types of workovers. This lesson explains why wells need workover

Lesson 1

1-1

repairs and what benefits usually result from workover operations. It also describes the general types of workovers and the well control equipment used with each type.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to:

1-2

•

Define the terms well completion, workover, and well servicing.

•

Explain the reasons for performing workovers.

•

Distinguish between different types of workovers.

Well Control for Workover Operations

Reasons for Workovers Although there are various reasons for workovers, most can be grouped into six basic categories: •

Repair or replace damaged equipment

•

Repair natural damage within the well

•

Recomplete to another zone

•

Increase production from an existing zone

•

Convert well from production to injection

•

Replace artificial-lift equipment

Repair or Replace Damaged Equipment Adverse downhole environments (e.g., erosion, chemical reactions, temperature extremes) can damage equipment during the life of a well. The following types of equipment may require repair: •

Tubing packers

•

Gravel pack equipment

•

Gas-lift mandrels and valves

•

Subsurface safety valves

•

Production tubing

•

Electric submersible pumps (ESPs) and rod pumps

For detailed descriptions of equipment, see Lesson 6, “Surface and Subsurface Equipment.”

Repair Natural Damage within the Well The term natural damage refers to damage in the reservoir rock or the fluids within it. Examples of this natural damage include near-wellbore formation damage, sand production, excessive gas production, and excessive water production. These types of damage and their causes are described in the following sections.

Lesson 1

1-3

Near-Wellbore Formation Damage During the producing life of a well, the permeability of the producing formation near the wellbore is reduced, affecting production rates. One reason for this nearwellbore damage is that components of the reservoir rock react with the well fluid. Examples of formation damage include: •

Swelling of fine formation clays within the reservoir rock pore spaces.

•

Blocked pore throats due to the migration of fine particles through the formation toward the wellbore.

•

Emulsion blockage caused by the mixing of two normally separate (immiscible) fluids such as completion brine and crude oil. The result is a highly viscous mixture that reduces the relative permeability of the producing formation.

•

Reduction of pore throat size due to the precipitation of scale—such as calcium carbonate or calcium sulfate—from reservoir fluids as a result of temperature or pressure reduction.

Sand Production Since many oil reservoirs are located in sand beds, sand production is a naturally occurring problem. As sand moves through the reservoir and the production string, it may plug perforations, safety valves, tubing, and surface equipment. It may also erode Christmas tree components. The rate of sand production can further increase due to formation breakdown, poor production practices, poor completions, and equipment failure. A common industry technique for controlling sand production is called gravel packing. Sized gravel particles are packed in the annulus outside a specially designed gravel-pack screen or slotted liner. Formation sand is then restricted from entering the completion. Gravel packing can be done in a cased hole or an open hole (Fig. 1-1). Various screen types are used for these procedures: pre-packed screens, gravel-pack screens, or simply screen assemblies.

1-4

Well Control for Workover Operations

Figure 1-1

Gravel packing

Excessive Gas Production In certain reservoirs, the gas associated with the oil serves as a major driving energy for oil production. The most common types of gas drives are solution-gas drives and gas-cap drives. In solution-gas drives, dissolved gas in the oil helps propel the oil to the surface. Eventually, some of this gas separates out of solution and becomes trapped above the oil, forming a gas cap. The energy in the gas cap then assists in propelling the oil. In some wells, the gas cap is already present when the well is completed. In either case, the gas in the cap may “cone” downward toward the perforations and be produced along with the oil. Coning robs the reservoir of drive energy and lowers production rates (Fig. 1-2). To control this separation during the early stages of production, the crew controls the pressure at which the well fluids are produced from the reservoir. Maintaining a certain pressure on the well helps keep the gas in solution with the oil. As the well fluids are produced, however, this separation is more and more difficult to maintain and a remedial workover may become necessary. This type of workover involves cementing the existing perforations and perforating a different zone to allow oil from below the oil-gas contact point to flow to the surface.

Lesson 1

1-5

Figure 1-2

Excessive gas production in oil wells

Excess Water Production (Coning) In waterdrive reservoirs, the energy propelling the oil or gas comes from the expansion of vast quantities of water. Water is generally considered incompressible, but it will compress and expand somewhat. Considering the enormous quantities of water present in a producing formation, this small expansion represents a significant amount of energy, which aids in driving the fluids through the reservoir to the surface. In this type of drive, the water tends to be drawn upward in the shape of a cone and eventually will reach the perforations (Fig. 1-3). As a result, water is produced, bypassing a portion of the oil reserves. Typically the first attempt to control coning involves reducing the production rate, but when this fails, a remedial workover may be needed to plug the perforations below the oilwater contact zone and produce from above the watered-out zone. In many cases, however, the water eventually covers the entire producing interval and a workover is performed to totally abandon that zone and, if possible, produce from another zone.

1-6

Well Control for Workover Operations

Figure 1-3

Water coning

Recomplete from One Zone to Another One of the most common reasons for a workover is to recomplete a well from one zone to another. Recompletion involves changing the zone from which the hydrocarbons are produced. Many wells are drilled to intentionally penetrate many zones, but only one zone at a time is produced. In some wells, lower zones are produced first. When depleted, they are recompleted (isolated) so that another zone farther up can be produced (Fig. 1-4). In some cases, higher zones are produced first and then recompleted to shift production to lower zones (Fig. 1-5).

Lesson 1

1-7

1-8

Figure 1-4

Recompletion to a higher zone

Figure 1-5

Recompletion to a lower zone

Well Control for Workover Operations

In some recompletions from a lower zone to a higher zone, the workover crew places a cement plug, bridge plug, or wireline set plug to isolate the abandoned zone (Fig. 1-6). This helps ensure that the old perforation is adequately sealed. In a recompletion from a higher to a lower zone where a plug is not used to isolate the zone, several squeeze cement jobs may be required to isolate the upper zones and seal the old perforations.

Figure 1-6

Zonal isolation

In most wells, an extra rathole (a space below the perforations) is drilled below the lowest production zone. A rathole provides clearance to run logging tools, collect produced formation material, or allow tubing-conveyed perforating guns (TCPs) to fall below the perforations. In some cases, bridge plugs or wireline plugs cannot be recovered from the wellbore, so the rathole provides a space for disposing of these plugs below the lowest-producing level where they will not affect production.

Lesson 1

1-9

Increase Production from an Existing Zone Production in a damaged or low-producing zone can be increased by one or more of the following techniques.

Acid or Solvent Stimulation Matrix acidizing is a stimulation technique involving injection of acid into the formation rock at pressures below the level at which the rock will fracture. This technique dissolves away damage caused by drilling, completion, and workover or well-killing fluids as well as by precipitation of deposits from produced water. It is also used to etch new channels or pathways for hydrocarbons near the wellbore. Hydrochloric acid (HCL) is used to treat limestone, dolomite, and other carbonatetype rocks, while hydrofluoric acid (HFL) is used in sandstone reservoirs. A mixture of HCL and HFL called “mud acid” is used to dissolve damaging clay deposits. Damage from waxes or asphaltenes in produced oil can be treated with organic solvents.

Hydraulic Fracturing In some wells it is necessary to intentionally fracture a formation to provide a deeper flow path for oil and gas into the wellbore. Fracture (“frac”) fluids include oil, water, acid, emulsions, foams, or combinations of these. The frac fluids are pumped downhole under high pressure at a high rate of flow to fracture the formation. These frac fluids include finely grained particles called proppants. Proppants are made from sand particles of a controlled size or sintered bauxite (aluminum ore). The proppant remains in the fracture to help hold the fracture open after pump pressure is bled off. An acid fracture job (often called “acid frac”) involves pumping a gelled acid at a pressure above the formation fracture limit. The gel creates a fracture, and the acid etches the rock surfaces, creating an irregular pattern. No proppant is used in an acid frac. When the earth’s forces cause the fracture to close, the uneven surface of the frac faces will not match and a new conduit for oil and gas is formed.

1-10

Well Control for Workover Operations

Steam Injection Steam is one type of stimulation technique for increasing production in zones of high-viscosity oil. Steam is injected into the formation to improve the oil’s flow properties. High-temperature equipment and appropriate workover procedures are required when steam injection is used to stimulate production.

Waterflood Injection and C02 Injection Waterflood injection and CO2 injection fall into the category of secondary recovery or enhanced oil recovery (EOR). Waterflood is a method used to increase production from an existing reservoir by injecting water into the reservoir to displace the oil. Generally, reservoirs that are geologically bounded on at least three sides are better candidates for waterflooding, since the water is trapped in place and not free to migrate out. The water generally used is produced formation water from a nearby source. CO2 injection (or “CO2 flood”) is a process by which carbon dioxide gas is injected into the reservoir to replenish drive energy and recover additional oil that would have otherwise been left in the reservoir. CO2 is often present in certain gas reservoirs in conjunction with hydrocarbon gas. Gas processing plants separate the CO2 from the hydrocarbon gas and send it to pipelines for transport to the field for injection. CO2 injection has been used for years in certain mature oilfields such as the Permian Basin in the southern United States.

Convert Well from Producer to Injector Workovers are done to convert producing wells to injection wells. In this type of workover CO2 or water can be injected, as previously discussed. Waste fluids or drilled cuttings can also be injected, which achieves the added objective of efficient disposal. For example, such a workover might involve converting a producing well configured for continuous or intermittent gas lift (see Fig. 6-7). Using wireline tools, the gas-lift valves are retrieved from their receptacles, or side-pocket mandrels, in the completion and replaced with special regulators that control the amount of gas injected into a particular zone in the reservoir. Typical injected gases include carbon dioxide (CO2) and produced field gas.

Lesson 1

1-11

Another example of a well conversion workover would be to reconfigure a well to inject produced water down the tubing and into the formation. Special regulators are installed in the completion string with wireline that control the volume of water injected to preengineered limits.

Replace Artificial-Lift Equipment When a reservoir does not have, or cannot maintain, sufficient drive energy to produce at an economical rate, assistance through artificial lift is required. There are four basic types of artificial lift: rod pump, hydraulic pump, electric submersible pump (ESP), and gas lift. For examples of artificial-lift equipment, see Fig. 6-6 and Fig. 6-7. Workover tasks for wells with artificial-lift operations may include: •

For rod pump: repair or replace the pump on the end of the sucker rod string. Damage may result from wear, fouling with sand, or pressure locking. This workover would involve using a rod pulling unit to retrieve the rod string from inside the production tubing. In some cases, the reciprocating motion of the rods abrades and eventually cuts through the production tubing. In this situation you must pull both the rod string and the production string.

•

For hydraulic pump: retrieve the pump through the tubing for repairs or replacement. In some instances, the tubing must be cleaned out first as scale or paraffin buildup may prevent the pump from passing through it.

•

For ESP: retrieve and repair or replace faulty ESPs and associated motors and electrical cable.

•

For gas lift: using wireline, retrieve and repair or replace gas-lift valves that have lost their functionality. (Damaged gas-lift valves may allow gas to pass straight through the valve with no restriction because the internal precharge has been lost or because the elastic parts, called bellows, have lost their resilience.)

Summary of Workover Benefits The benefits of workovers can be summarized as follows: 1

1-12

Relieve excessive back pressure resulting from plugged formations or obstructions in the wellbore or surface equipment.

Well Control for Workover Operations

2

Repair or replace damaged wellbore equipment (e.g., corroded, scaled-up, or leaking production equipment).

3

Repair near-wellbore formation damage.

4

Relieve natural problems such as gas-cap production or water coning.

5

Increase production by isolating a depleted zone and completing another.

6

Improve the flow of oil that is too viscous to flow easily.

7

Increase permeability by opening natural fractures or creating new ones and improving the connection between the formation and the wellbore (e.g., hydraulic fracturing operations).

8

Replace artificial-lift equipment.

Types of Workovers and Associated Well Control Equipment This section lists key points and equipment configurations for four basic types of workovers:

Lesson 1

•

conventional workover

•

concentric workover

•

wireline workover

•

workover with a pump unit or pump truck

1-13

Conventional Workover Key Points 1

Well is killed and barriers are installed and tested.

2

Christmas tree is removed.

3

BOP equipment is nippled up and tested. For testing procedures, see “BOP Equipment Testing” on page 6-49.

4

Pipe or tubing is used as work string.

Well Control Equipment •

Annular

•

Rams

•

Choke manifold

•

BOP closing unit

•

Floor safety valves

•

Trip tank

Figure 1-7

1-14

Conventional workover rig and equipment

Well Control for Workover Operations

Concentric Workover Key Points 1

Workover is done through Christmas tree and tubing bore.

2

Small tubing or coiled tubing is commonly used.

3

Well may or may not have pressure.

4

BOPs are installed above tree (see “Workover Implementation” on page 8-11).

Well Control Equipment •

Stripper or annular

•

Rams (hydraulic or manual)

•

Choke manifold or chicksans

•

Accumulators or hand pumps

•

Floor safety valves

Figure 1-8

Lesson 1

Concentric workover using coiled tubing unit

1-15

Wireline Workover Key Points 1

Workover is completed through Christmas tree.

2

Wireline is used instead of work string.

3

Well may or may not have pressure.

4

Lubricator is installed.

Well Control Equipment •

Pack-off assembly

•

Lubricator assembly

•

Special wireline BOPs

•

Small hand pump

•

Floor safety valves

Figure 1-9

1-16

Wireline workover equipment Well Control for Workover Operations

Workover with Pump Unit (Reversing Unit) Key Points 1

Workover is completed through Christmas tree.

2

Well generally has pressure.

3

Existing tubing is used as work string.

4

Workover unit is used primarily to kill producing wells.

Well Control Equipment •

Pump truck

•

Pump and prime mover

•

Pressure relief valve

•

Pump lines

•

Working valve

•

Chicksans

Figure 1-10 Pump unit and equipment

Lesson 1

1-17

1-18

Well Control for Workover Operations

2 WELL CONTROL PRINCIPLES AND CALCULATIONS Lesson Overview During a workover procedure the well-site supervisor (WSS) and crew must contain the formation fluids within the formation while remedial work is being carried out. An undesired flow of these fluids into the wellbore is called a kick. If a kick fluid enters and moves up the wellbore, it has a tendency to expand and unload fluid above it. This may result in an uncontrolled and potentially dangerous flow of formation fluids from the wellbore. There are three main goals of well control: •

Prevention of kicks by maintaining wellbore hydrostatic pressure at a level equal to or slightly greater than formation pressure (primary well control)

•

Early detection of kicks that do occur

•

Initiation of corrective action to prevent kicks from developing into uncontrolled flow

In order to accomplish these goals, the WSS first needs a clear understanding of the basic physical principles of well control and the calculations required to apply these principles. This knowledge allows the supervisor to relate the data from surface indicators (e.g., gauge readings, fluid tank levels) to the situation downhole (e.g., pressures, volumes, fluid types) and take corrective action. By applying the appropriate principles and calculations to the well control situation, the supervisor should be able to: • Lesson 2

Correctly interpret surface indicator data. 2-1

•

Eliminate small problems before they become bigger problems on the surface.

•

Determine the controls needed to execute a workover kill operation.

•

Choose the appropriate well control procedure for a given situation.

•

Diagnose problems during well control procedures and take corrective action.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to: •

Describe the basic well control principles commonly used in the oilfield (e.g., the U-tube concept, friction pressure distribution in a wellbore, and additive wellbore hydrostatic pressures).

•

Select and correctly use the appropriate well control formulas—given the well control information found on the rig (e.g., gauge readings, fluid densities, depth measurements, etc.)—to determine what is occurring in the wellbore.

•

Calculate the quantities, volumes, pressures, and rates required to handle well control operations on the rig.

Overview of Workover Well Control Calculations Basic workover well control calculations are shown in Fig. 2-1. These calculations and the surface indicators used with them can be divided into three general groups:

2-2

•

Wellbore and formation fluid pressures

•

Wellbore fluid volumes and workover fluid volumes

•

Wellbore forces (acting on BOPs, plugs, packers, etc.)

Well Control for Workover Operations

Well & Workover Fluid Volumes

Well & Formation Pressures

Pressure Forces

Surface Indicators

Calculations

Surface Indicators

Calculations

Calculations

• SITP

• Hydrostatic pressure

• Tank volume

• Gradient

• Actual pump output

• Tubing and casing volumes and capacities

• Cross sectional area

• Differential force

• Static BHP

• Annulus volumes and capacities

• Formation pressure

• Displacement volumes

• SICP • Friction Pressure Indicator

• Equivalent fluid weight • Balanced fluid weight

• Pressure force

• MASP Figure 2-1

Overview of workover well control calculations and indicators

Surface Indicators of Pressure Surface indicators of pressure (i.e., tubing and casing pressure gauges) will allow you to infer what the downhole pressures are and how they change with time. You can use these pressure readings for many well control calculations. Monitoring these pressures can help you prevent burst casing, formation damage, lost circulation, and other well control problems. It is important, therefore, that you report them accurately and monitor them carefully. Two important pressure indicators are the shut-in tubing pressure (SITP) gauge and the shut-in casing pressure (SICP) gauge. The SITP gauge is connected to the bore of the tubing or work string (see Fig. 2-2). How you use the SITP reading depends on the circulation path that will be used to control the well. If the circulation is forward (down the tubing and up the annulus), you will generally control the well over the long term with the tubing gauge. (In addition to the SITP reading, you will use the SICP reading to assist in initially

Lesson 2

2-3

establishing circulation, which is called “bringing the well on choke.”) You will also use the SITP reading to estimate pressure at the bottom of the hole and to calculate the fluid weight needed to balance the well. The SICP gauge is connected to the annulus (see Fig. 2-2). How you use the SICP reading also depends on the circulation path that will be used to control the well. If the circulation path is reverse (down the annulus and up the tubing), you will generally control the well over the long term with the annulus gauge. (In this situation, you will use the SITP gauge reading to bring the well on choke.) During certain specialized well control procedures, the SICP gauge reading is used to control bottomhole pressure when fluid must be pumped into the top of the well or bled out of the well (see “Volumetric Method” on page 3-40).

Figure 2-2

SICP and SITP gauges

Friction Pressure Energy is required to move fluid through the wellbore at a certain rate.In order to move, the fluid must overcome the frictional forces between the particles of the fluid itself and between the fluid and the surfaces it contacts (tubing wall, annulus walls, and string restrictions). The pump generates energy to overcome this friction; this energy is commonly called friction pressure or “pump pressure.” 2-4

Well Control for Workover Operations

Understanding the downhole effect of this friction pressure is important knowledge for the WSS.

Friction Principles 1

The total friction pressure (or pump pressure) is sum of the individual frictional resistances along the fluid flow path. Resistance is found in: •

The surface lines from the pump to the rig floor

•

The tubing or work string

•

The annulus

•

Internal string restrictions such as selective landing nipples and sliding sleeves (Fig. 6-3 and Fig. 6-14)

In a workover with typical completion geometry, 65–95% of the friction is generated in the tubing and the remainder in the annulus. This is due to a higher fluid velocity inside the smaller tubing diameter compared with that in the larger annulus. 2

The total friction (and hence the pump pressure) does not change with the circulation path. The total friction is the same forwards or backwards (3+2 = 2+3). The pump pressure will be the same whether forward circulating (down tubing, up annulus) or reverse circulating (down annulus, up tubing).

3

The frictional pressure applied to points downhole does change with the circulation path. When the fluid leaves the pump, its energy is progressively used up. The energy (friction pressure) that has been used cannot exert force on the wellbore or formation; only the remaining energy can. Said another way, the pressure exerted on any point in the wellbore is equal to the sum of the frictional resistances downstream (ahead) of that point. In reverse circulation, the friction pressure exerted on the formation perfs (just outside the mouth of the tubing) equals the total downstream resistance (i.e., the tubing friction). This can be a significant amount of pressure. In forward circulation, the tubing friction pressure is expended by the time the fluid reaches the end of the tubing; it is not “felt” by the formation perfs. What is felt is the total downstream friction at that point, i.e., the annulus friction pressure, which is generally less.

Fig. 2-3 illustrates some examples of these principles.

Lesson 2

2-5

Figure 2-3

Tubing/annulus friction pressure distribution

According to the first two principles, the indicated pump pressure is the same for both forward and reverse circulation (a sum total of 1,000 psi). Notice, however, that the friction pressure exerted on the formation is considerably different.The formation is exposed to 750 psi friction pressure in reverse circulation, but only 200 psi in forward circulation. The third principle explains this difference: when the fluid leaves the pump, friction is lost along its path until it reaches the bottom of the hole. In forward circulation, 50 psi pump line friction plus 750 psi tubing friction is lost. This leaves 200 psi, which is the downstream pressure exposed to the formation, as stated in the third principle above. In reverse circulation, only 250 psi is lost by the time the fluid reaches bottom, leaving 750 psi downstream pressure at the mouth of the tubing. The 750 psi is exposed to the formation (550 psi higher than forward circulation). The WSS needs to be aware of this invisible effect when choosing the circulation path. Although the pressure differential cannot be seen on the pump gauge (it reads

2-6

Well Control for Workover Operations

the same in both cases), the effect is “felt” downhole. If the formation perfs are exposed, whole fluid may be pumped away or the formation fractured. Note that the example in Fig. 2-3 is an open well that is being circulated. Shut-in wells in the circulating condition are covered later in this lesson (see “Dynamic Pressure Analysis” on page 2-34). The friction pressure principles still apply, but they are easier to understand in the open well case, which is mathematically simpler. Depending on your geographic location, you will hear other terms used to describe friction pressure—“friction drop,” “pressure drop,” “friction loss,” “dynamic pressure,” and “ECD.” ECD (equivalent circulating density) is not a correct synonym for friction pressure, however. ECD is actually the sum of the fluid weight plus the “equivalent” weight of the friction pressure. The values used for the friction pressures in the previous example are illustrative values only, not actual values. At the well site, you should use a computerized hydraulics program to determine friction pressures for the well, based on the specific wellbore geometry and fluid properties that you have supplied. (Even though these calculations can be done manually, it is a tedious process and prone to math mistakes.)

Calculations Related to Well and Formation Pressure This section presents calculations that the WSS uses to plan and execute workover operations. These calculations provide values for the following: •

hydrostatic pressure and pressure gradient

•

crude oil hydrostatic pressure

•

equivalent fluid weight (FW)

•

balanced fluid weight (FW)

•

static well analysis

In the examples that follow, field units (English) will be used. (For metric unit conversion factors, see “Conversion Factors” on page A-10 in the Appendix.)

Lesson 2

2-7

Hydrostatic Pressure and Pressure Gradient Hydrostatic pressure is the pressure exerted by a column of fluid due to its own weight. The amount of pressure is dependent on the density (weight) of the fluid, expressed in pounds per gallon (ppg), and the vertical height of the fluid column, based on true vertical depth (TVD). TVD is the depth of a well measured from the surface straight to the bottom of the well, as opposed to the length of the wellbore, or measured depth (MD). All wells have both measurements. In a vertical well, TVD and MD will be the same, but in a deviated wellbore the two measurements will not be equal (Fig. 2-4). To determine hydrostatic pressure, always use TVD.

Figure 2-4

2-8

True vertical depth (TVD) and measured depth (MD)

Well Control for Workover Operations

The following equation is used to calculate hydrostatic pressure.The conversion factor 0.052 is used in the equation to change the final answer to pressure, expressed as pounds per square inch (psi).

Hydrostatic Pressure (psi) = Fluid Weight (ppg) × (0.052) × TVD (ft) Example 1: Given: A 10,000 ft TVD well contains 10.0 ppg workover fluid. Find: Hydrostatic pressure Solution: Hydrostatic Pressure = 10,000 × 10 × 0.052* = 5,200 psi Example 2: Given: A deviated well of 8,000 ft TVD and 10,200 ft MD. The well contains10.2 ppg of workover fluid. Find: Hydrostatic pressure at bottom of well Solution: Hydrostatic Pressure = 10.2 × 0.052* × 8,000 = 4,243 psi *conversion factor to yield psi

A pressure gradient (or simply gradient) is a measure of the pressure exerted by one foot of a vertical column of fluid. The gradient is expressed in psi/ft. Therefore, if a fluid had a gradient of 1 psi/ft, then a 10,000-foot column of this fluid would exert 10,000 psi (10,000 × 1 psi/ft). If the fluid had a gradient of 0.5 psi/ft, then a 10,000foot column would exert 5,000 psi (10,000 × 0.5), and so on. Gradient is commonly reported in wellbore data and is the basis for many oilfield calculations. Formation data, completion data, and workover fluid data are often reported as gradients as a matter of convenience.The WSS must know how to manipulate the gradient to perform various calculations.

Lesson 2

2-9

Pressure Gradient (psi/ft) = Fluid Weight (ppg) × 0.052 Fluid Weight (ppg) = Pressure Gradient (psi/ft) ÷ 0.052 Example 1: Given: Workover fluid with a density of 9.6 ppg Find: Pressure gradient of the fluid Solution: Pressure Gradient = 9.6 × 0.052 = 0.499 psi/ft Example 2: Given: Workover fluid with a gradient of 0.530 psi/ft Find: Fluid weight (density) Solution: Fluid Weight = 0.530 ÷ 0.052 = 10.192 = 10.2 ppg

The fluid weight in Example 2 is rounded to 10.2 ppg. Rounding up to the nearest tenth is standard practice because fluid densities can be measured only to this level of accuracy on the rig. In addition to using pressure gradient to find fluid weight, you can use it to help determine the hydrostatic pressure of the well fluid. Hydrostatic pressure is calculated in different ways, depending on the known data—such as the pressure gradient of the workover fluid and the TVD of the well.

Hydrostatic Pressure = Pressure Gradient (psi/ft) × TVD (ft) Example: Given: Workover fluid with a gradient of 0.520 psi/ft at 8,762 ft TVD Find: Hydrostatic pressure of the fluid Solution: Hydrostatic Pressure = 0.520 × 8,762 = 4,556.24 = 4,556 psi

2-10

Well Control for Workover Operations

Crude Oil Hydrostatic Pressure Crude oil is often encountered during workover operations. Although crude exerts hydrostatic pressure like any other fluid, its density is temperature sensitive, and a correction must be applied to the hydrostatic calculation to take this factor into account. Furthermore, crude density is often measured and reported in another unit system called API gravity or “API degrees.” An API gravity of 10 is equal to the density of fresh water. As the API gravity number increases, the density decreases. For example, API gravity 12 (API 12°) is lighter oil than API 10 (API 10°). Oil density is measured with an API hydrometer that is calibrated to 60°F. Rarely is the temperature of the oil 60°F when it is measured. The following equations can be used to make the necessary correction for temperature.

If observed temperature > 60°F: (Observed Temp - 60) Observed Density (on hydrometer) – ------------------------------ = API corrected 10 If observed temperature < 60°F: (60 - Observed Temp) Observed Density (on hydrometer) – ------------------------------ = API corrected 10

After the density has been corrected for temperature, the hydrostatic pressure can be calculated using the following formula:

141.5 Hydrostatic Pressure = ------------------------------ × .433 × TVD ( 131.5 + API corrected )

For an example of crude oil density and pressure calculations, see Summary of Equations on page A-2 in the Appendix.

Lesson 2

2-11

Equivalent Fluid Weight (FW) Pressures, expressed in psi units, are often converted to their fluid weight “equivalents” (expressed in ppg units) for the convenience of simplifying comparisons between downhole pressures and the fluid weight required to balance those pressures. The pressures most commonly converted to an equivalent fluid weight include gauge pressures, friction pressures, formation pressures, and test pressures. Pressure gradients (expressed in units of psi/ft) can also be converted to equivalent fluid weights.

Equivalent Fluid Weight = Pressure (psi) ÷ TVD (ft) ÷ 0.052 Equivalent Fluid Weight = Pressure Gradient (psi/ft) ÷ 0.052 Example 1: Given: Shut-in tubing pressure (SITP) of 2,600 psi and a well depth of 9,854 ft TVD Find: Equivalent fluid weight (FW) Solution: Equivalent FW = 2,600 ÷ 9,854 ÷ 0.052 = 5.07 = 5.1 ppg Example 2: Given: Formation pressure gradient of 0.530 psi/ft Find: Equivalent fluid weight of the formation Solution: Equivalent FW = 0.530 ÷ 0.052 = 10.19 = 10.2 ppg

In Example 2 above, the formation would exert a pressure equivalent to that of a fluid with a density of 10.2 ppg density. This is a standard way of reporting formation data. It is common to hear “the formation is a 10.2 equivalent” or “it’s a 10.2-pound formation.” Although some of the terms used in the field may not be mathematically precise, it’s a good idea to be familiar with them so you can better communicate with others.

2-12

Well Control for Workover Operations

Balanced Fluid Weight (FW) Balanced fluid weight is the fluid weight equivalent of the formation pressure for a particular well. The calculation for balanced fluid weight is the same as that for equivalent fluid weight: pressure (psi) ÷ TVD ÷ 0.052. Once you have determined the balanced fluid weight of the formation, you can compare it with the density of the fluid in the wellbore. It may be necessary to weight up the fluid to that density to balance the formation pressure, which is an important method of controlling formation fluids. (In the oilfield, the terms kill fluid weight or simply “kill weight” are often used interchangeably to refer to the balanced fluid weight. These terms are discussed in more detail in “Kill Fluid Weight” on page 2-14.)

Balanced Fluid Weight = Formation Pressure (psi) ÷ TVD (ft) ÷ 0.052 Balanced Fluid Weight = Formation Gradient (psi/ft) ÷ 0.052 Example: Given: Documented formation pressure of 9,800 psi for a well at 14,300 ft TVD Find: Balanced fluid weight (FW) Solution: Balanced FW = 9,800 ÷ 14,300 ÷ 0.052 = 13.179 ppg = 13.2 ppg It is advisable to add a hydrostatic pressure safety margin to the balanced fluid weight. Sometimes called overbalance, this safety margin provides extra pressure in the wellbore to avoid underbalance caused by choke manipulation, pipe movement, or fluid temperature changes as well as unknown pressures encountered in formations. The amount of safety margin varies from well to well and area to area in a range of up to 200 psi.

Lesson 2

2-13

Balanced Fluid Weight (with safety margin) = ( Safety Margin (psi) + Formation Pressure (psi) ) ÷ TVD (ft) ÷ 0.052 Example: Given: Documented formation pressure of 9,800 psi for a well at 14,300 ft TVD Find: Balanced fluid weight (FW) with a 200 psi safety margin Solution: Balanced FW = (200 + 9,800) ÷ 14,300 ÷ 0.052 = 13.45 = 13.5 ppg In these examples, the difference between the overbalanced fluid weight and the balanced fluid weight is 0.3 ppg (13.5 - 13.2 = 0.3), which might be referred to in the field as 3 “points” of overbalance. A difference of, say, 2.0 ppg would be referred to as 2 “pounds” of overbalance.

Kill Fluid Weight Kill fluid weight is the weight of a drilling fluid that allows that fluid to equal or exceed the pressure exerted by the formation fluids. Although formation pressures taken from recent production test data can be used to calculate kill fluid weight, this data may not always be accessible or accurate. You can, however, apply other principles explained in this lesson to determine the kill fluid weight. For example, you will most often have an SITP reading and some knowledge of the nature of the fluid inside the tubing. Fig. 2-5 illustrates a set of sample conditions found in a workover well along with the calculations for determining balanced and overbalanced kill fluid weights for this set of conditions.

2-14

Well Control for Workover Operations

Kill Fluid Weight (balanced) = ( SITP ÷ TVD perfs ÷ 0.052 ) + Tubing Fluid Weight Example 1: Find: Kill fluid weight at top perfs Solution: Kill FW = (1,900 ÷10,570 ÷ 0.052) + 6.7 = 10.16 ppg = 10.2 ppg* Example 2: Find: Kill fluid weight at mid perfs Solution: Kill FW = (1,900 ÷ 10,670 ÷ 0.052) + 6.7 = 10.12 ppg = 10.2 ppg* *Kill FW always rounded up to next 0.1 ppg Kill Fluid Weight (Overbalanced) = [ (SITP + Overbalance) ÷ TVD perfs ÷ 0.052 ] + Tubing Fluid Weight Example 3: Find: Kill fluid weight at mid perfs with 150 psi overbalance Solution: Kill FW = [(1,900 + 150) ÷ 10,670 ÷ 0.052)] + 6.7 = 10.39 ppg = 10.4 ppg Figure 2-5

Calculating kill fluid weight (balanced and overbalanced)

Theoretically, the kill fluid weight calculated for the top set of perforations (top perfs) should be higher than that for the middle set (mid perfs). Comparing Examples 1 and 2 of the sample calculations above, however, shows that the difference is insignificant. If the total length of perforations were greater than that in the example, or if the perforation depth were much shallower, the difference could be significant. Using the top perforation depth would be more conservative. Client policy, however, may dictate calculating at certain points.

Lesson 2

2-15

Static Bottomhole Pressure Static bottomhole pressure (BHP) is the pressure at the bottom of the wellbore when the well is static (not circulating). In Fig. 2-5, the static BHP is equal to the SITP plus the hydrostatic pressure of the oil column inside the tubing. If there were several different fluids in the tubing, the static BHP would be the total of their hydrostatic pressures plus the SITP. In a shut-in well in communication with the perforations (that is, where there are no plugs or blocks and the pressure can be transmitted freely), the static BHP is also equal to the formation pressure.

Static Bottomhole Pressure (BHP) = SITP + Total Tubing Hydrostatic Pressure Example: Given: SITP = 1,900 psi, tubing fluid weight = 6.7 ppg, TVD = 10,670 ft (see Fig. 2-5) Find: Static bottomhole pressure at mid perfs Solution: BHP = 1,900 + (6.7 × 0.052 × 10,670) = 5,617 psi

Calculating bottomhole pressure is important when killing wells. Later lessons will describe methods for maintaining as well as manipulating bottomhole pressure.

Static Well Analysis Fig. 2-6 shows a shut-in well in the static (noncirculating) condition. You can use the information in this figure and the principles explained thus far in this lesson to understand:

2-16

•

The principle of additive pressures

•

Why the casing pressure differs from the tubing pressure

•

The U-tube effect

Well Control for Workover Operations

Figure 2-6

Lesson 2

Sample conditions for static well analysis

2-17

Static Well Analysis Example 1: Finding static BHP Given: Conditions in Fig. 2-6 Find: Static BHP Solution: BHP = SITP (160) + Total Tubing Hydrostatic Pressure (10,600 × 0.052 × 9.2) = 5,231 psi The BHP of 5,231 psi pushes up on the annulus. Thus, the SICP represents the BHP pushing up minus the total hydrostatic pressure in the annulus pushing down. To calculate SICP, add all the individual pressures in the annulus and subtract the total from the BHP, as follows: Example 2: Finding annulus hydrostatic pressure and proving SICP Given: BHP from Example 1 (5,231 psi) Find: Total annulus hydrostatic pressure and prove the SICP in Fig. 2-6 Solution: Total annulus hydrostatic pressure = brine below gas (100 × 0.052 × 9.2) + gas (1,000 × 0.108) + brine above gas (9,500 × 0.052 × 9.2) = 4,701 psi SICP = BHP (5,231) - Total Annulus Hydrostatic Pressure (4,701) = 530 psi Example 3: Finding tubing hydrostatic pressure and proving SITP Given: BHP from Example 1 (5,231 psi) Find: Total tubing hydrostatic pressure and prove the SITP in Fig. 2-6 (This calculation may seem redundant, but it gives practice in calculating from the bottom to the top of the well.) Solution: Total tubing hydrostatic pressure = TVD (10,600) × 0.052 × tubing fluid weight (9.2) = 5,071 psi SITP = BHP (5,231) - tubing hydrostatic (5,071) = 160 psi These static well analysis calculations illustrate some very important principles. In these examples the SICP is higher than the SITP because the column of fluids in the annulus is lighter in weight than the fluid column in the tubing; thus, it pushes down 2-18

Well Control for Workover Operations

with less force against a constant BHP pushing up. The result is a higher gauge reading. If the annulus fluid weight had been heavier than the tubing fluid weight, then the SITP would have been higher. Understanding how the SICP and SITP reflect downhole conditions is essential for the WSS. In a shut-in well, the total pressure on the tubing side (including the gauge pressure) must balance the total pressure on the casing side (including the gauge pressure). Stated another way, the SITP equals the bottomhole pressure minus the total tubing hydrostatic pressure, and the SICP equals the bottomhole pressure minus the total annulus hydrostatic pressure. This principle of balanced pressures is referred to as the U-tube effect. The WSS must understand this principle to diagnose downhole conditions and control the well. (See the workbook for practice problems related to the U-tube effect.) Since U-tube pressures are balanced and equal, you might wonder why all the formulas above use readings from the tubing side for calculating values for kill fluid weight, BHP, and so on. The reason is that, in most cases, you know with reasonable accuracy the nature of the liquid in the tubing and its associated density, whereas the annulus may be filled with mixtures of contaminated liquids and gas of unknown quantities and densities and could lead you to err in determining kill fluid weight and BHP. Generally you should use the tubing side to calculate both of these measures.

Calculations Related to Well and Workover Fluid Volumes This section presents calculations for fluid volumes that the WSS must take into account during workover operations. The calculations provide values for the following:

Lesson 2

•

tubing and casing capacities

•

annular capacities

•

displacement volume

•

fluid tank volumes

•

pump output

•

hydrostatic pressure loss when pulling pipe

•

dynamic pressure analysis

2-19

In the examples that follow, field units (English) will be used. (For metric unit conversion factors, see “Conversion Factors” on page A-10 in the Appendix.)

Tubing and Casing Capacities Tubing capacity, in common oilfield usage, refers to the internal volume of a particular size of tubing per unit length (bbl/ft). A more precise term would be capacity factor. Once you know the capacity factor, you can calculate the total internal volume of the tubing or casing.

Internal Volume Calculations Capacity Factor (bbl/ft) = Inside Diameter (inches)2 ÷ 1029.4* Internal Volume (bbls) = Capacity Factor (bbls/ft) × Length (ft) Example: Given: 10,000 ft of tubing with 2-3/8" OD × 4.7 pounds per foot (ppf) Find: Internal volume in bbls Solution: Capacity Factor = (1.995)2 ÷ 1029.4 = 0.00387 bbls/ft Internal volume = 0.00387 × 10,000 = 38.7 bbls *conversion factor to yield bbl/ft

Figure 2-7

Determining tubing or casing capacity factor and volumes

The formulas used to calculate the capacity factor and volume of a drilled hole are identical to those above for a workover operation.These drilling calculations would be needed when deepening or sidetracking the well during a workover.

2-20

Well Control for Workover Operations

Annular Capacities An annulus is formed when one tubular occupies the space inside another, or a tubular is inside a drilled hole. In common oilfield usage, the term annular capacity sometimes refers to the unit volume per foot of annular length (bbl/ft); at other times it refers to the total volume (bbls) in the annulus. A more precise term for unit volume per foot is annular capacity factor. The annular capacity factor is used to determine total annular volume in bbls, known as annular volume. In these calculations, casing size is based on inside diameter (ID) whereas tubing size is based on outside diameter (OD).

Annular Volume Calculations Annular Capacity Factor (bbls/ft) = [Casing ID (inches)2 Tubing OD (inches)2] ÷ 1029.4 Annular Volume = Annular Capacity Factor (bbls/ft) × Length (ft) Example: Given: 10,000 ft 2-3/8"; 4.7ppf tubing inside 5-1/2"; 17 ppf casing Find: Annular volume in bbls Solution: Annular Capacity Factor = (4.8922 - 2.3752) ÷ 1029.4 = 0.01777 bbl/ft Annular Volume = 0.01777 × 10,000 = 178 bbls

Figure 2-8

Lesson 2

Determining annular capacity factor and annular volume

2-21

Displacement Volume The displacement volume of a tubular is the amount of liquid the tubular displaces when it is run into the hole. This volume is equal to the volume of steel in the tubular. If tubing is run into the hole, the steel displaces liquid in an amount equal to its displacement volume. Conversely, as tubing is pulled out of the hole, the liquid fills in the void left by the tubing and the fluid level drops in proportion to the displacement volume. “Closed-end displacement” refers to a situation in which the tubing is plugged (intentionally or otherwise) when it is run into the hole. Because fluid is not free to fill the inside of the tubing, the displacement volume increases significantly. The term displacement is often used to mean the unit displacement per foot of tubing (bbl/ft), but it may also mean the total displacement volume in barrels. Displacement factor is a more precise term for describing the unit displacement, and displacement volume, or total displacement, for the total displacement volume.

2-22

Well Control for Workover Operations

Displacement Calculations Displacement Factor (bbls/ft) = Pipe Weight (ppf) ÷ 2750* Displacement Factor (bbls/ft)** = [Tubing OD (inches)2 – Tubing ID (inches)2] ÷ 1029.4 Displacement Volume (bbls) = Displacement Factor (bbls/ft) × Length (ft) Closed-end Displacement Factor (bbls/ft) = OD (inches) 2 ÷ 1029.4 Example 1: Given: 10,000 ft of tubing 2-3/8" ID; 4.7 ppf Find: Steel displacement volume in bbls Displacement Factor = 4.7 ÷ 2750* = 0.00171 bbls/ft Displacement Volume = 0.00171 × 10,000 = 17.1 bbls Example 2: Given: 10,000 ft of tubing 2-3/8" ID; 4.7 ppf Find: Closed-end displacement in bbls Displacement Factor = 2.3752 ÷ 1029.4 = 0.00548 bbl/ft Displacement Volume = 0.00548 × 10,000 = 54.8 bbls *2750 valid for steel only **Considers tube only, not coupling

Figure 2-9

Lesson 2

Determining displacement factor and displacement volumes

2-23

Tubing, casing, and annular capacity factors and displacement factors can also be found in tables in the Schlumberger Cementing Services Manual. It is useful to know how to calculate these factors, however, if you are using a tubular size that is not included in the manual or if the manual is not available.

Fluid Tank Volumes Fluid tanks hold workover fluid at the surface. Knowing the volume at the surface and monitoring any volume changes is very important. During workover operations, monitoring tank volumes can reveal the presence of influx in the wellbore or loss of fluid downhole. A pit volume totalizer system usually monitors the fluid tank volumes on a drilling rig, but not all workover rigs have this system. Some fluid tanks are marked to show what a vertical drop or increase in liquid level represents in number of barrels and thus can help monitor downhole conditions. But since tanks sent to a workover rig may not be marked to reflect accurate volumes, the WSS must be able to determine tank volumes with several equations and a tape measure. Tank volume can be used to obtain the tank capacity factor, expressed in volume per unit of tank depth (bbls/inch), which can help you equate a vertical drop or rise in tank level with a specific volume.

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Well Control for Workover Operations

Rectangular Rig Tank Volume Tank Volume (cubic feet or ft3) = Length (ft) × Width (ft) × Depth (ft) Tank Volume (bbls) = Tank Volume (ft3) ÷ 5.61* Tank Capacity Factor (bbls/inch) = Tank Volume (bbls) ÷ Tank Depth (ft) ÷ 12 Example: Given: Rig tank measuring 20' 10" L × 8' 0" W × 6' 3" H Find: Tank volume and tank capacity factor Solution: Convert dimensions to decimals 20'10" = 20 + 10/12 = 20.83' 8' 0" = 8.0' 6' 3" = 6 + 3/12 = 6.25' Tank Volume (ft3) = 20.83 × 8.0 × 6.25 = 1,041.5 ft3 Tank Volume (bbls) = 1,041.5 ÷ 5.61 = 185.65 bbls Tank Capacity Factor = 185.65 ÷ 6.25 ÷ 12 = 2.46 = 2.5 bbl/in *conversion factor to convert cubic feet to bbl

The tank volume equation above will work for a cube-shaped tank as well; the length and width would simply be the same number. The equations for calculating capacity factors and volumes of cylindrical vertical tanks are found in “Summary of Equations” on page A-2 in the Appendix.

Pump Output The WSS must be able to determine the pump output (volume per pump stroke) of the positive displacement pumps on the rig. Although pump manufacturers provide output information, it may not be available at the rig site or it may no longer be

Lesson 2

2-25

accurate due to pump wear or poor maintenance. If the measured output is 25% less than the rated output, the integrity of the pump is questionable. During a well control operation, it is imperative for the WSS to base calculations and pump rate selection on true pump output and not the manufacturer’s data or a number believed to be correct by the rig crew. Pump output calculations vary somewhat, depending on whether the pump is equipped with a stroke counter. Pump with Stroke Counter

Actual Pump Output (bbl/stroke) = bbls pumped ÷ strokes recorded Procedure: 1

Zero the stroke counter.

2

Pump a measurable volume, 5 or 10 bbls, into a calibrated tank.

3

Record the number of strokes pumped.

4

Calculate the output.

Example: Given: 5 bbls, pumped into a calibrated tank; 71 strokes recorded Find: Actual pump output in bbl/stroke Solution: Pump Output = 5 ÷ 71 = 0.070 bbl/stroke The workover procedure may call for pumping at a certain volume rate in barrels per minute (bpm). Even if a rig has a stroke counter, you cannot accurately calculate bpm without knowing that the pump is putting out the correct volume per stroke. To ensure accuracy, the actual output is used to calculate the required pump speed, expressed in strokes per minute (spm).

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Well Control for Workover Operations

Required Pump Speed (spm) = Required Volume Rate (bpm) ÷ Actual Pump Output (bbl/stroke) Example: Given: Workover procedure requiring volume rate of 3.0 bpm; actual pump output of 0.070 bbl/stroke (see previous example) Find: Required pump speed in spm Solution: Required Pump Speed = 3.0 bpm ÷ 0.070 bbl/stroke = 42.9 = 43 spm

Pump without Stroke Counter On some workover rigs stroke counters are not installed on the pumps, so the rig crew may have to estimate pump output based on the tachometer reading for the engine driving the pump. To determine the actual pump rate (bpm) in this case, use the following procedure and calculations.

Lesson 2

2-27

Actual Pump Rate (bpm) = barrel increase in tank ÷ minutes pumped Procedure: 1

Align pump to pump from one tank and discharge to another tank that is calibrated to measure volume.

2

Have the rig contractor operate the pump at the rate he believes it is operating (e.g., 2 bpm). An experienced contractor’s estimate will usually be close to the actual rate.

3

Pump at the above rate for an even increment of time (e.g., 1 minute, 5 minutes, etc.).

4

Record barrel increase in discharge tank.

5

Calculate actual pump rate.

Example: Given: Pump operated at a rate of 2 bpm for 5.0 minutes, with increase of 9.5 bbls Find: Actual pump rate in bpm Solution: Actual Pump Rate = 9.5 bbl ÷ 5.0 min = 1.9 bpm

These examples demonstrate several ways of obtaining accurate pump information. The calculations and procedures serve as a toolbox of knowledge for the WSS who will be responsible for the results of a well kill. As explained in later lessons, circulation times will differ from what you expect if the pump is not delivering output at the assumed rate. Knowing true pump rates will also help you maintain correct bottomhole circulating pressure as you kill a well, without imposing too much or too little friction pressure against the formation.

Additional Practice in Pump Calculations The following workover example combines several of the situations and calculations provided earlier to give you a workover case study.

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Well Control for Workover Operations

Workover Example Given: You are in charge of a workover rig in a remote location. There is no accurate output data for the positive displacement pump (which has a stroke counter). You instruct the crew to pump between tanks for about 200 strokes and record the exact number of strokes pumped as well as the inches gained in the discharge tank. The crew reports 214 strokes and a gain of 10 inches. Fluid tank dimensions: 8' (W) × 15' (L) × 6' 6" (H) Tubing: 3-1/2" × 9.3 ppf, ID = 2.995" Tubing and annulus length = 12,200 ft Casing ID = 6.995" Workover specification: displace tubing and annulus at 2.5 bpm Find: Tank calibration (bbls/in), bbls required, actual pump output, total strokes, required pump speed, and total minutes Solution: 1. Tank calibration Volume (ft3) = 8.0 × 15.0 × 6.5 = 780.0 ft3 Volume (bbls) = 780.0 ÷ 5.61 = 139.04 bbls Required volume bbls/in = 139.04 ÷ 6.5 ÷ 12 = 1.78 bbls/in 2. Bbls required Tubing Capacity Factor = 2.9922 ÷ 1029.4 = 0.00870 bbl/ft Tubing Volume = 0.00870 × 12,200 = 106.1 bbl Annulus Capacity Factor = (6.9952 - 3.52) ÷ 1029.4 = 0.03563 bbl/ft Annular Volume = 0.03563 × 12,200 = 434.7 bbl Total bbls required = 434.7 + 106.1 = 540.8 = 541 bbls 3. Actual pump output (bbl/stroke) Bbls pumped = 10 inches × 1.78 bbl/in = 17.8 bbls Output = 17.8 bbls ÷ 214 strokes = 0.0832 bbl/stroke 4. Total strokes = 541 bbls ÷ 0.0832 bbl/stroke = 6,502 strokes 5. Required pump speed = 2.5 bbls/min ÷ 0.832 bbl/stroke = 30.04 = 30 spm 6. Total minutes = 6,502 strokes ÷ 30 spm = 217 minutes

Lesson 2

2-29

Hydrostatic Pressure Loss When Pulling Pipe The calculations and concepts in this section combine principles for hydrostatic pressure, displacements, and capacities. It is important to remember that the hydrostatic pressure in the well drops when the fluid level drops while pulling production tubing from the hole. You must also be able to quantify (put a number to) the loss of hydrostatic pressure when the fluid level drops. If you are unaware of this effect or ignore it for too long, the well can become underbalanced and begin to flow. You could experience a kick or even a blowout. Fatalities, environmental damage, well damage, and loss of rigs have occurred because the hydrostatic pressure drop was not carefully monitored and controlled. As you pull tubing from a well, you remove steel volume from the liquid in the hole, and the liquid level drops to fill in this space. A drop in liquid level reduces hydrostatic pressure and thus bottomhole pressure. If the level drops both inside and outside the tubing, you are pulling dry pipe. The hydrostatic pressure loss caused by pulling dry pipe is given below.

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Well Control for Workover Operations

Hydrostatic Pressure Loss (Dry Pipe) Displacement Factor × Length Pulled Fluid Level Drop (ft) = ---------------------------------------------------------------------( Annular Capacity Factor + Tubing Capacity Factor ) ( Tubing wt/ft ÷ 2750 ) × Length Pulled = -------------------------------------------------------------------------------2 2 ( Casing ID – Tubing OD ÷ 1029.4 ) + ( Tubing ID ÷ 1029.4 ) Hydrostatic Pressure Loss = Fluid Level Drop (ft) × Fluid Weight (ppg) × 0.052 Example: Given: 1,000 ft of tubing with 2-7/8" OD and 6.5 ppf inside casing with 5-1/2" ID and 17 ppf (4.892" ID), 10.2 ppg completion fluid in wellbore Find: Fluid level drop and loss of hydrostatic pressure Solution: ( 6.5 ÷ 2750 ) × 1,000 Fluid Level Drop = ---------2---------------------------------------2-------------2 ( 4.892 – 2.875 ÷ 1029.4 ) + ( 2.441 ÷ 1029.4 ) 0.00236 × 1,000 = ------------------------ = 112.33 ft 0.01522 + 0.00579 Hydrostatic Pressure Loss = 112.33 × 10.2 × 0.052 = 59.58 = 60 psi As the example shows, if you pull 1,000 feet of tubing without filling the hole, you lose 60 psi hydrostatic pressure due to fluid level drop. Even more important; you would lose 60 psi of bottomhole pressure, which might be enough to cause the well to flow, depending on the well condition.

Lesson 2

2-31

Hydrostatic Pressure Loss (Wet Pipe) Fluid Level Drop (ft) = ( Displacement Factor + Capacity Factor ) × Length Pulled ----------------------------------------------------------------------------(Annular Capacity Factor) 2

( ( Tubing wt/ft ÷ 2750 ) + ( Tubing ID ÷ 1029.4 ) ) × Length Pulled -----------------------------------2---------------------------------------------------2 ( Casing ID – Tubing OD ) ÷ 1029.4 Hydrostatic Pressure Loss = Fluid Level Drop (ft) × Fluid Weight (ppg) × 0.052 Example: Given: 1,000 ft of 2-7/8"OD, 6.5 ppf tubing (2.441" ID) inside 5-1/2" ID, 17 ppf casing (4.892" ID), 10.2 ppg completion fluid in wellbore Find: Fluid level drop and loss of hydrostatic pressure Solution: 2

( ( 6.5 ÷ 2750 ) + ( 2.441 ÷ 1029.4 ) ) × 1,000 Fluid Level Drop = --------------------2------------------------------------2 ( 4.892 – 2.875 ) ÷ 1029.4 ( 0.00236 + 0.00579 ) × 1,000 = -------------------------------------- = 535.37 ft 0.01522 Hydrostatic Pressure Loss = 535.37 × 10.2 × 0.052 = 59.58 = 284 psi* * Compare this hydrostatic pressure loss to that of the dry pipe example. The tubular sizes and fluid weights are identical, yet the hydrostatic pressure loss is over four times as great. Since you are pulling the contents of the pipe out of the hole as well as the metal, the displacement for wet pipe is significantly higher than that for dry. Therefore the fluid level drop and resulting hydrostatic pressure loss are proportionally higher.

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Well Control for Workover Operations

In certain geographic areas, there may be regulations concerning the amount of pipe that can be pulled from a well without filling the hole as well as a requirement that this amount must be calculated and posted near the driller’s station on the rig. In that case, it is convenient to rearrange the equation to solve for this amount, as shown in the following example

Hydrostatic Pressure Effect Sample Regulation: “When coming out of the hole with a work string, the annulus shall be filled with well control fluid before the change in fluid level decreases the hydrostatic pressure by 75 psi. The number of stands (or feet) that may be pulled and the equivalent well control fluid volume shall be calculated and posted near the driller’s station.” Allowable Pipe Displacement Volume = Allowable Pressure Loss (psi) × ( Tubing Capy. Factor + Ann. Capy. Factor ) ----------------------------------------------------------------------------------------------------0.052 × Fluid Weight (ppg) Pipe Length Equivalent to Allowable Volume

Displacement Volume × 2750 = --------------------------------------Pipe Weight (ppf)

Example: Given: A well with tubing of 2-7/8" OD and 6.5 ppf (2.441" ID) is inside casing of 5-1/2", 15.5 ppf (4.950" ID); fluid weight is 10.2 ppg. Find: Allowable displacement volume of pipe that can be pulled to comply with the sample regulation above (assume an allowable loss of 75 psi) and equivalent length. Solution: Allowable Displacement Volume = 75 × ( 0.00579 + 0.01577 ) ---------------------------------- = 3.048 bbl 0.052 × 10.2 Equivalent Length =

Lesson 2

3.048 × 2750 ----------------- = 1, 290ft 6.5

2-33

Dynamic Pressure Analysis So far, this lesson has presented only static bottomhole pressure calculations. As stated earlier, static bottomhole pressure refers to the pressure at the bottom of the hole (or pressure acting against the formation) with the pumps off. As you learned earlier, however, friction pressure caused by moving fluid exerts additional pressure downhole. Therefore, when the pumps are running, as will be the case in most workover kill procedures, you can expect extra pressure downhole. This pressure, in addition to the hydrostatic pressure of the workover fluid, will create circulating bottomhole pressure. As mentioned earlier, the magnitude of the pressure will depend on the circulation path. Furthermore, the extra frictional pressure downhole is “invisible” on the surface—it cannot be read on the pump gauge. Understanding wellbore physics is important if you are to control downhole conditions. Fig. 2-10 and the sample calculation illustrate this concept.

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Well Control for Workover Operations

Figure 2-10 Conditions for determining circulating bottomhole pressure

Lesson 2

2-35

Circulating Bottomhole Pressure Given: Tubing friction = 2,400 psi; annulus friction = 300 psi; hydrostatic pressure = 5,200 psi (see Fig. 2-10) Find: Circulating bottomhole pressure (BHP) and pump pressure for forward and reverse circulation Solution: 1. Forward circulation Circulating BHP = Hydrostatic Pressure + Annulus Friction Loss Circulating BHP = 5,200 psi + 300 psi = 5,500 psi Pump Pressure = Total Friction = 300 psi + 2,400 psi = 2,700 psi 2. Reverse circulation Circulating BHP = Hydrostatic Pressure + Tubing Friction Loss Circulating BHP = 5,200 psi + 2,400 psi = 7,600 psi Pump Pressure = Total Friction = 2,400 psi + 300 psi = 2,700 psi Note that in Fig. 2-10 the surface indicators (pump pressures) are identical but the bottomhole pressures differ by 2,100 psi (7,600 - 5,500 = 2,100). As discussed in a later lesson (see “Reverse Circulation Method” on page 3-19), there are valid reasons for choosing reverse circulation over forward, but you must be aware that the two paths can produce significant differences in bottomhole pressure. Reverse circulation does not always yields higher bottomhole pressures. In a well with large tubing and a relatively small annulus, as in a high-volume gas well completion, reverse circulation would actually yield a lower bottomhole pressure. Bottomhole pressure is a function of the relative frictional pressures, not merely the circulation path.

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Well Control for Workover Operations

Forces A force can be defined as a push or a pull on an object. Although there are many types of forces downhole, a workover crew must be especially concerned with pressure force and differential force.

Pressure Force The force created by wellbore pressure, often referred to as pressure force, can be a safety concern to people and equipment. The WSS must know where pressure force exists, the extent of the force, and how to avoid its effects. To determine the pressure force on a typical round section of equipment (e.g., a plug, a pipe, a packer), you must first calculate the area of the cross-section.

Cross-Sectional Area (in2) = 0.7854* × Outside Diameter2 Example: Given: Plugged pipe with 5" OD Find: Cross-sectional area (in2) Solution: Area = 0.7854 × 52 = 19.64 in2 *a constant equal to the value π ÷ 4"

Figure 2-11 Determining cross-sectional area

Lesson 2

2-37

Pressure Force (pounds) = Pressure (psi) × Area (in2) Example: Given: Closed-end pipe with area of 19.64 in2, shut-in BOP under 3,000 psi Find: Pressure force on pipe Solution: 3,000 × 19.64 = 58,920 lbs of upward force

Figure 2-12 Determining pressure force on a cross-sectional area

The total upward force generated on the pipe in the example above is 58,920 pounds. Because the force is coming from the bottom of the hole toward the surface, it is trying to eject the pipe from the hole. In fact, the pipe would be ejected from the hole if the sum of the weight of the pipe and the frictional force of the BOP ram rubbers totaled less than 58,920 pounds. Although this is a simplified example, it illustrates why the WSS must be aware of these pressure forces when performing workover operations.

Differential Force A differential force (or delta force) exists when the force acting on an object in one direction is different from that acting in the opposite direction. Fig. 2-13 illustrates differential force on a plug placed in a tubing bore during a workover. The net force on the plug is equal to the difference in formation pressure force pushing upward and the force of the hydrostatic pressure of the tubing fluid pushing downward (sometimes called delta pressure). In this example the differential force is 22,500 pounds. If the plug were released suddenly, it would be propelled up the hole. Therefore it is standard practice to equalize the pressure across these plugs before attempting to release them. A lubricator assembly should also be installed.

2-38

Well Control for Workover Operations

Example: Formation Pressure = 8,000 psi Hydrostatic Pressure = 5,000 psi Delta Pressure = 3,000 psi Plug Area = 7.5 in2 Force = 3,000 × 7.5 = 22,500 lbs

Figure 2-13 Differential force

Differential force can also exist across downhole packers. The magnitude of this force on packers can be much larger than that of plugs due to the larger crosssectional area of the packers. Differential forces on packers can be hundreds of thousands of pounds. Sand bridges sometimes occur inside tubing that completely block the tubing bore, thus isolating the tubing above the bridge from formation pressure. Tremendous differential forces can build up across these bridges. The WSS must be aware of this possibility and plan to keep adequate fluid weight on top of the bridge before it is penetrated to prevent damage to equipment or loss of well control.

Lesson 2

2-39

The Barrier Concept While a workover is in progress, physical barriers are necessary to prevent kicks because the usual controls and conditions that prevent kicks during drilling are not present. Workover conditions that differ from drilling conditions include the following: •

Formations are more permeable since they have been perforated, stimulated, or hydraulically fractured.

•

Overbalanced conditions sustained in drilling are difficult to sustain in workover wellbores that contain open, permeable zones.

•

Workovers do not normally use a solids-laden fluid to deposit an impermeable filter cake, so the formation is more likely to take fluid, resulting in a loss of hydrostatic column height and possibly a loss of primary well control.

A barrier, as defined in Standard IPM-ST-WCI-012, is “any impervious material or device that can be demonstrated to temporarily or permanently prevent the flow of wellbore and reservoir fluids.” For a fluid to be considered a barrier, its hydrostatic pressure must be greater than the formation pressure and its condition and position must be capable of being monitored. Monitoring includes knowing the density of the fluid and the level of the fluid. The fluid level is most accurately determined by taking a sonic “picture” of the top of the fluid using a device called an echometer, which is described in Lesson 6. Barriers are divided into the following classes: •

Primary barriers are those used during normal workover operations. They include such tools as a wireline stuffing box (see Fig. 6-17) or a workover fluid providing hydrostatic pressure.

•

Secondary barriers are used in support of normal operations or as a contingency (e.g., an annular preventer or back-pressure valve).

•

Tertiary barriers are used in emergencies—e.g., a shear or blind ram or a tree master valve used to cut wireline (see Fig. 6-26 and Fig. 6-23).

Standard IPM-ST-WCI-012 requires at least two barriers at all times. The WSS should review this entire standard to ensure compliance with all its conditions. (For a list of standards applicable to workovers, see “IPM Standards” on page A-14 in the Appendix.)

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Well Control for Workover Operations

Gas Behavior in the Wellbore Wellbore gas behaves according to a gas law that can be expressed mathematically as follows: P1 × V 1 = P2 × V2 where P1 = initial gas pressure (psi) V1 = initial gas volume (bbls) P2 = final gas pressure (psi) V2 = final gas volume (bbls) For simplicity, the equation here does not include the effects of compressibility and temperature. As the equation shows, gas pressure and gas volume are related: •

If the pressure on the gas decreases, its volume must increase and vice versa.

•

If the volume of a gas increases, its pressure must decrease and vice versa.

•

If the volume of a gas remains the same, its pressure will remain the same.

Gas Expansion in an Open Wellbore Fig. 2-14 illustrates gas behavior in an open wellbore as it moves upward, expanding according to the gas law.

Lesson 2

2-41

Example: A 5 bbl gas bubble rises through 12 ppg completion fluid to the top of a 10,000 ft open well. P1 = 0.052 × 12 × 10,000 = 6,240 psi V1 = 5 bbls V2 = P1 × V1 ÷ P2 What is the gas volume when the bubble has risen halfway to the surface (5,000 ft)? V2 = 6,240 × 5 ÷ 3,120 = 10 bbls What is the gas volume when the bubble has risen three-fourths of the way to the surface, or half the previous distance (2,500 ft)? V2 = 6,240 × 5 ÷ 1,560 = 20 bbls What is the gas volume when the bubble has risen seven-eighths of the way to the surface, or half the previous distance (1.250 ft)? V2 = 6,240 × 5 ÷ 780 = 40 bbls What is the gas volume when the bubble exits the wellbore into the atmosphere (atmospheric pressure = 14.7 psi)? V2 = 6,240 × 5 ÷ 14.7 = 2,122 bbls Figure 2-14 Gas expansion according to the gas law

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Well Control for Workover Operations

As the illustration shows, the gas volume doubles each time it moves one half its previous distance because the hydrostatic fluid pressure on the gas is halved each time. This doubling effect becomes quite apparent near the top of the wellbore, where it accelerates. A gas influx that is allowed to move this far up the wellbore undetected will result in a strong increase in flow as workover fluid is pushed out of the well above the gas. Without primary well control, more gas can enter the wellbore from the formation, further accelerating the process until all the fluid has been blown out of the well, resulting in uncontrolled flow from the formation.

Gas Expansion in a Wellbore Being Killed In the previous example, the well is open at the top, as when displacing fluids during normal workover operations or when tripping the tubing or work string into or out of the hole. During workover kill operations, the well is closed in with the BOPs. A choke is used to control back pressure on the well, which maintains constant bottomhole pressure while the kick is being removed from the wellbore. In a wellbore, gas will still expand as it moves up the wellbore, but the amount of expansion will not be as great as in an open well. The gas law explains this: since additional back pressure is applied to the wellbore and hence to the gas itself, the pressure on the gas is greater and its volume increase must be less. Typically, as the gas moves from the bottom to the top of the well, its volume increases about three to four times its original volume at shut-in. Compare this volume increase to that illustrated in Fig. 2-14. Associated with the increase in gas volume is an increase in casing pressure, as expected. The expanding gas pushes the heavier wellbore fluid out the top of the well through the choke. Since gas is lighter than wellbore fluid, the annulus becomes progressively lighter. The annulus acts as a force pushing down against the formation force pushing up. If the annulus force decreases, the casing pressure must increase to compensate. This casing pressure increase is illustrated in Fig. 3-4 and Fig. 3-8.

Gas Migration in a Closed Wellbore Fig. 2-15 illustrates gas migration, another mode of gas behavior. In the oilfield, the term gas migration refers to the undesirable condition of gas moving upward in a totally closed-in well without the freedom to expand. If the gas cannot expand, then its volume cannot change and, according to the gas law, its pressure cannot change Lesson 2

2-43

either. The gas moves up the wellbore at its original pressure. This has a detrimental effect, increasing the pressure at every point in the wellbore, including the pressure on the casing, the tubing, the formation, the surface gauges, and the bottomhole pressure.

Example: A 5 bbl gas bubble rises through 12 ppg completion fluid to the top of a 10,000 ft closed-in well. The formation pressure is 6,240 psi. What is the bottomhole pressure (BHP) after the gas has risen 5,000 ft? BHP = pressure of the gas + hydrostatic pressure of the completion fluid below the gas Hydrostatic Pressure = 0.052 × 12.0 × 5,000 = 3,120 psi BHP = 6,240 + 3,120 = 9,350 psi What is the bottomhole pressure (BHP) after the gas has risen to the top of the well (10,000 ft)? BHP = pressure of the gas + hydrostatic pressure of the completion fluid below the gas Hydrostatic Pressure = 0.052 × 12.0 × 10,000 = 6,240 psi BHP = 6,240 + 6,240 = 12,480 psi Figure 2-15 Effect of gas migration on bottomhole pressure

As Fig. 2-15 illustrates, gas migration causes a dramatic increase in bottomhole pressure, in this case doubling (from 6,240 psi to 12,480 psi). In reality, however,

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Well Control for Workover Operations

the excessive wellbore pressure would most likely start to force wellbore fluid into any open perforations in the formation, giving the gas room to expand. This situation is still undesirable because it will result in formation damage and loss of control of the well. The various ways of controlling the detrimental effects of gas migration are explained in a subsequent lesson (see “Procedures for Controlling Gas Migration” on page 3-38).

Lesson 2

2-45

2-46

Well Control for Workover Operations

3 WELL CONTROL PROCEDURES Lesson Overview A conventional workover usually begins with a well control procedure or a well kill through the Christmas tree to establish primary well control. Primary well control is the maintenance of fluid hydrostatic pressure greater than formation pressure. The well is then secured with mechanical barriers, the Christmas tree is removed, and the BOPs are installed and tested. The workover then continues with a “quiet” well under primary well control. Unfortunately, many workover well conditions are not favorable for primary well control. These workover conditions include the loss of clear fluid into open perfs, swabbing due to tight mechanical clearances, and the presence of wellbore gas when clear fluids are in the hole. The gas will migrate quickly up the hole and expand, making primary well control difficult. Any of these conditions can lead to well flow, which will require shutting in the well and killing it a second time before operations can continue. The kill procedures in this lesson fall into the category of secondary well control. Secondary well control is applied when primary well control is lost or cannot be maintained. Secondary well control involves using additional mechanical barriers such as BOPs and tree valves along with the rig pumps and a high-pressure circulating system as well as specific procedures to control pressure and reestablish primary well control. The goals of secondary well control include the following:

Lesson 3

•

Circulate formation fluid out of the well.

•

Force formation fluid back into the formation.

3-1

•

Avoid additional kicks.

•

Reestablish primary well control.

•

Avoid excessive surface and downhole pressures.

In drilling, most wells are drilled to total depth (TD) without the need for a well kill. Workovers, however, present many “opportunities” for a well kill. It is very important, therefore, that you be familiar with all of the well control procedures presented in this lesson and to be able to execute them correctly.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to: •

Define the terms primary well control and secondary well control.

•

Describe the procedures for recording slow circulating rate pressures (SCRPs) and understand their purpose.

•

Correctly describe how to shut in a well.

•

Describe procedures for bleeding trapped pressure from a well.

•

Describe the procedure for obtaining SITP with a back-pressure valve or check valve in the work string.

•

Describe applications and procedures and correctly execute calculations for the following well control methods:

•

3-2

•

Wait-and-weight

•

Constant pump pressure

•

Reverse circulation

•

Bullheading

Describe the following procedures for controlling gas migration: •

Constant tubing pressure method

•

Volumetric method

Well Control for Workover Operations

•

Describe the procedures for removing gas from the wellbore (lubricate-andbleed) •

Volume method

•

Pressure method

Recording Slow Circulating Rate Pressure Slow circulating rate pressures (SCRPs) are observed and recorded (or, in field terminology, “taken”) when the crew has the pipe on bottom and is circulating. The crew takes the SCRP routinely, usually every shift, so that if the well must be shut in, the SCRPs will already be recorded and available. The crew uses the prerecorded SCRP to calculate the pressure they must use during a well control procedure (see the calculations in Fig. 3-6). Depending on geographic location, SCRP may be referred to as “kill rate pressure,” “slow pump rate,” “slow circulating rate,” “reduced-speed pump pressure,” “dynamic pressure loss,” or “slow pump pressure.” The term SCRP will be used throughout this manual in accordance with the Schlumberger Well Control Manual. SCRP is defined as the pump pressure at any rate that is less than the normal circulating rate used to do work on a well when the well is open. Wells are killed at these slower speeds to improve control when operating the choke, to limit the amount of friction pressure imposed on the formation, and to slow down the rate at which wellbore gas loads up the surface handling system. After the workover crew initially kills the well and replaces the tubing with a work string, they record a group of three or four SCRPs and their corresponding pump pressures. The crew also takes the SCRPs when there is a change in fluid density, viscosity, or type; a change in work string ID, OD, or length; or a change in an internal restriction. For example, if a milling job will require a bottomhole assembly (BHA) of a few drill collars and a mill, the geometry of the string would differ from an open-ended string (which may have been initially run in the hole). In this case, the crew would need to take additional SCRPs. Or if the crew ran an appreciable length of wash pipe, the string geometry would be sufficiently different to have a noticeable effect on circulating pressures and would require additional SCRPs. Table 3-1 shows an example of recorded SCRPs.

Lesson 3

3-3

Table 3-1

Typical Kill Rate Pressures

SPM

BPM

PSI

30 40 50

1.0 1.4 1.8

630 1180 1890

Shut-in Procedures The importance of containing a kick and keeping the influx volume to a minimum cannot be overemphasized. Large kicks lead to high wellbore and surface pressures and large volumes of kick fluids that must be handled on the surface. The shut-in, or containment, procedures can vary, depending on the type of equipment in use and the operation in progress at the time of the kick, whether on-bottom circulating or tripping. The shut-in procedures explained below apply to a conventional workover rig. Due to the limited wellbore volumes available in a completed well or one being worked over, it is imperative that minimal time be expended in shutting in a well. The rig crew will carry out these procedures; the WSS must ensure the crew is competent and prepared to do so. The WSS’s responsibilities are detailed in Lesson 8, “WSS Roles and Responsibilities.” It should be noted that in the drilling industry, these procedures would be regarded as “hard” shut-ins (i.e., the choke is in the closed position when BOPs are closed). In workover well control, however, the terms “hard” and “soft” are not applied to shut-in procedures, and the procedures do not have names. These shut-in procedures are designed to be as simple and effective as possible in securing the well, allowing the smallest possible influx volume. The procedures should be posted near the driller’s station, and the WSS should make sure the rig crew clearly understands them.

Shut-in Procedure for Conventional Workover Rig (On-Bottom Circulating) Initial lineup: •

3-4

Kill BOP valves are closed.

Well Control for Workover Operations

•

Path is open from BOP valves to choke.

•

Choke is closed.

Use the following steps to shut in the well: 1

With pump(s) running, pick up work string until a tool joint is above floor level.

2

Shut down pump(s) and watch for flow.

3

If the well is flowing, close work string valve with its closing tool. This tool should be stored in a conspicuous location on the rig floor.

4

Close annular BOP. If there is no annular BOP, use the pipe rams.*

5

Open the choke line valves on the stack to gain access to casing pressure.

6

Notify the WSS that the well is shut in.

7

Monitor and record SITP, SICP, and pit gain.

*If pipe rams are used, make sure the string is at a height that avoids closing the pipe ram on a tool joint or tubing connection across the stack. You should know this height in advance.

Shut-in Procedure for Conventional Workover Rig (Tripping) Initial lineup: •

Kill BOP valves are closed.

•

Path is open from BOP valves to choke.

•

Choke is closed.

•

Work string safety valve and wrench are available on floor.

•

Safety valve is in open position.

Check the well for flow; if it is flowing, use the following steps to shut in the well:

Lesson 3

1

Position a connection for stabbing at rig floor.

2

Install open work string safety valve. Close valve with a wrench.

3

Close annular BOP. If there is no annular BOP, use the pipe rams.*

4

If the work string is less than 3,000 feet long, or if there is a packer on the tubing string, space out the work string and close and lock a pipe ram.**

3-5

5

Open the choke line valves on the stack to gain access to casing pressure.

6

Notify the WSS that the well is shut in.

7

Read and record SITP, SICP, and pit gain.

*If pipe rams are used, make sure the string is at a height that avoids closing the pipe ram on a tool joint or tubing connection across the stack. You should know this height in advance. **Locking the pipe ram resists the force of the wellbore pressure as it attempts to eject the string from the well.

Procedure for Shutting In Well for the Night (Daylight Rigs) Many workover rigs are not equipped with lighting and cannot operate at night. They must therefore be shut in before dark. Use the following steps to shut in and secure the well:

3-6

1

Circulate at least one bottoms-up circulation to check for the presence of gas in the workover fluid. This step will require running tubing to the bottom if it is not already there. If this is an open-hole completion, leave the work string inside the casing. If the well has been taking fluid, consider spotting a fluid loss pill across the suspect zone. (For more information on spotting a fluid loss pill, see “Mixing and Spotting a Kill Pill” on page 5-24.)

2

Make up a pup joint on the top of the tubing string. Lower the string, close the pipe rams on the pup joint, and lock the pipe rams. (The pup joint collar below the rams will prevent upward movement of the tubing string in the presence of unforeseen well pressure that might build overnight.)

3

Install the tubing safety valve and a pressure gauge on top of the pup joint. (This gauge and valve allow you to make a safely check for pressure the next morning.)

4

Close the safety valve.

5

Consider securing the tubing string with a chain and binder or other suitable device to further prevent upward movement.

Well Control for Workover Operations

Procedure for Opening Well in the Morning (Daylight Rigs) It is not uncommon for a gas bubble to enter the wellbore overnight. Given the long time period, a slow feed in of gas can accumulate into a sizeable volume overnight. If you open the well, a pressure release and flow will result. Follow these steps before reopening the well for normal workover operations: 1

Check the tubing string pressure gauge by opening its needle valve. If no pressure registers on the gauge, check for flow past the safety valve.

2

Check the annulus pressure gauge. If no pressure registers, check for annular flow. Normally you check for flow through the choke manifold.

3

If there is no pressure or flow on either the tubing or the annulus, is it safe to open the well. If there is pressure or flow, you must kill the well with the appropriate procedure before proceeding. (Kill procedures will be discussed later in this lesson.)

Additional Shut-in Considerations In addition to shutting in the well, consider the following points: 1

Make sure the crossovers are on the floor so that the work string safety valve can be installed onto any component of the work string.

2

Familiarize yourself with the closing volumes of the preventers to be used.

3

Inspect the BOP stack, choke manifold, and BOP hydraulic system for leaks shortly after shut- in.

4

Make sure someone continuously monitors shut-in pressures and records them at least once every 3 to 5 minutes.

5

When a manual BOP is used, note the number of turns to close the BOP.

Trapped Pressure at Shut-in When shut-in pressures are initially recorded following the initial buildup (Fig. 3-1), it is important to determine whether these pressures are accurate—that is, whether they are representative of the differential between formation pressure and wellbore hydrostatic pressure. Complications such as trapped pump pressure and rapid gas migration can affect their accuracy.

Lesson 3

3-7

The following procedures can be used to detect the presence of trapped pressure and to remedy the situation if any is found. Perform this trapped pressure check only after surface pressures have stabilized (after an initial period of rapid buildup).

Procedure for Checking for Trapped Pressure Use the following procedure with the graphs in Fig. 3-1: 1

Bleed a small amount of fluid through the choke (1/4 to 1/2 bbl). Surface pressures will initially decrease, build, and then stabilize.

2

Observe SITP. If the SITP stabilized at a value less than the previously observed stable pressure and trapped pressure was detected and at least partially bled off, continue with the procedure.

3

Bleed another small amount of fluid through the choke and once again observe the stabilized SITP.

4

Accurate SITP is verified when consecutive and identical values appear on the tubing gauge. In a workover, the SITP will often bleed to 0 psi.

Fig. 3-1 and Fig. 3-2 provide graphic representations of the bleeding process and accompanying SITP and SICP readings.

Figure 3-1

3-8

Pressure profile during bleeding with mechanically induced kick

Well Control for Workover Operations

Fig. 3-1 shows the bleeding process when the crew handles a mechanically induced kick (i.e., a kick induced by not keeping the hole full during trips, swabbing, etc.). As is customary in many workovers and completions, when the SITP bleeds to 0 psi, the density of the fluid in the hole is sufficient to balance formation pressure.

Figure 3-2

Pressure profile during bleeding with light fluid in the hole

In Fig. 3-2, the SITP did not bleed to 0 psi, presenting clear evidence that the fluid in the hole is lighter than required. Although rare, this can occur when light fluid is pumped into the well, creating a reduction in overall hydrostatic pressure and causing a kick.

Procedure for Obtaining the SITP with a BPV in the String Fig. 3-3 depicts a situation in which the SITP cannot be read due to the presence of a back-pressure valve (BPV) or check valve in the work string, a common occurrence in workovers. Nevertheless, an accurate reading is required to calculate kill fluid density, ICP, etc. Use the following procedure to pump the valve open and determine the SITP:

Lesson 3

3-9

1

Line up the manifold to pump into the tubing and monitor the gauge.

2

Slowly pump into the tubing (e.g., at a rate of 1/4 to 1/2 bpm); the pressure will increase. When the BPV first opens, the pressure will stop rising momentarily (the gauge needle “stutters” or hesitates).

3

Record the exact SITP pressure reading when the gauge needle hesitates.

Continued pumping at this point will further increase the pressure and is not useful. If there is a computer logging service on location, request a plot of pump pressure versus strokes. It is easy to see the pressure stabilization point on a graph (it looks very similar to the breakover point in the leak-off test done in drilling).

Figure 3-3

BPV or check valve in string

Circulating Well Control Procedures The following procedures are called circulating well control procedures, not merely because a pump is used, but because there is a full circulating path for the fluids, either down the tubing and back up the annulus or vice versa. On the downstream side of the path (the side away from the pump), an adjustable choke is used to

3-10

Well Control for Workover Operations

control the correct gauge pressure in order to keep bottomhole pressure constant. It is not simply an open-well circulation (although that is done in workovers). The well is closed in with a BOP, making it a circulating well control procedure. These procedures include the wait-and-wait method, the constant pump pressure method, and reverse circulation.

Wait-and-Weight Method This well control method had its beginnings in the drilling industry and is widely used in that arena. Although it is not the predominant kill method in workover well control, it can be used. For a description of this method in a workover, see “Well Scenario: Wait-and-Weight Method” on page 3-15. The name of the method is indicative of what happens—you wait until the fluid is weighted up to the correct density and then kill the well. Whether the fluid density should be increased is determined by the stable SITP reading. If the SITP does not bleed to 0 psi (after a check for trapped pressure), then the fluid density is insufficient and must be weighted up. The density can become insufficient for the following reasons: •

Mismanagement of the fluid on the surface, resulting in light fluid being pumped downhole.

•

Formation fluid contamination of the fluid in the tubing.

•

Penetration of a zone of higher formation pressure, as when sidetracking or washing through sand plugs.

The wait-and-weight method, by design, is a one-circulation kill procedure. Kill fluid is pumped in while the influx is circulated out. If performed properly, it will require the least amount of “on choke” time. Furthermore, it should result in lower ultimate casing pressure than other circulating methods because the increase in hydrostatic pressure of the kill weight fluid in the annulus offsets the decrease in hydrostatic pressure caused by gas expanding in the annulus above it. A drawback to this method is the time required to weight up and condition the fluid before pumping begins. In the event of a gas influx, the time required to condition and weight up may allow gas migration to take place, requiring surface pressure monitoring and controlled bleeding of fluid until the actual well killing operation can begin. This controlled bleeding process will be addressed later in this lesson (see “Constant Tubing Pressure Method” on page 3-39).

Lesson 3

3-11

Additionally, the WSS must generate a circulating “pressure schedule” and use it to monitor the tubing pressure while displacing the tubing string. Tubing pressure will gradually decrease as the tubing string is displaced to kill fluid—that is, filled with kill weight fluid. This decrease in tubing pressure is the result of kill fluid hydrostatic pressure replacing the original underbalance shown on the tubing gauge.

Wait-and-Weight Procedure Follow these steps to kill a well with the wait-and-wait method: 1

Calculate and increase the fluid weight to kill value (see Fig. 2-5).

2

Create a tubing pressure reduction schedule (see Fig. 3-5). Monitor the well for gas migration. Use the choke to maintain tubing pressure within 50–100 psi above the original SITP.

3

Line up the manifolds and the pump to circulate kill fluid down the tubing and take returns from the annulus.

4

Bring the pump to the predetermined kill speed (one of the speeds at which SCRPs were taken) while holding the annulus pressure constant with the choke. These steps will establish initial circulating pressure (ICP) on the tubing gauge. If the value observed on the gauge does not agree with the calculated value, use the observed value. Verify the observed reading by repeating the startup procedure. If you obtain the same reading a second time, consider it valid. You will have to modify the tubing pressure schedule so it reflects the new value. Do not change the pressure gauge reading (with the choke) to fit the pressure schedule. Change the pressure schedule to fit the observed gauge reading. This can be done quickly without stopping circulation.

5

Circulate the kill fluid to the end of the tubing following the pressure schedule from ICP to final circulating pressure (FCP).

6

Once the kill fluid is in the annulus, hold the tubing pressure constant at FCP until the kill fluid returns to the surface.

7

Shut down the pumps and check for well flow. Close the choke and check for pressure on the tubing or casing gauge.

Fig. 3-4 shows the pressure profiles for the wait-and-weight method. Note the sloped portion of the pump pressure line between ICP and FCP. This portion pertains to the pressure reduction schedule you will create. Also note that FCP is reached when the kill fluid reaches the end of the tubing. At this point, continue

3-12

Well Control for Workover Operations

pumping, holding the tubing gauge (pump) pressure constant at the FCP value by manipulating the choke. Perhaps the most important thing to learn from the figure is that although two pressures are plotted, the pump pressure is the “process control.” Use the choke to control pump pressure, not the casing pressure, except for a short time during the pump-start procedure.

Figure 3-4

Pressure profile for wait-and-weight method

Wait-and-Weight Calculations 1

Obtain accurate SITP and SICP readings.

2

Calculate tubing or work string volume in barrels or strokes (see Fig. 2-7). Record this number on the pressure reduction schedule (step 1 on the schedule in Fig. 3-5).

3

Calculate Kill Fluid Weight. (Use the appropriate equation depending on information available.) Kill FW = (SITP ÷ TVD perfs ÷.052) + Tubing Fluid Weight Kill FW = Formation Pressure (psi) ÷ TVD (ft) ÷.052 Kill FW = [Safety Margin (psi) + Formation Pressure (psi)] ÷ TVD (ft) ÷.052

4

Determine Initial Circulating Pressure (ICP). Record this number on the pressure reduction schedule (see Fig. 3-5). Calculated ICP = SITP (psi) + SCRP (psi)

Lesson 3

3-13

Observed ICP: Use the stabilized pump pressure reading after the pump-start procedure. 5

Calculate Final Circulating Pressure (FCP). FCP = SCRP (psi) × Kill (or balance) Fluid Weight (ppg) ÷ Original Tubing Fluid Weight (ppg)

6

Create Tubing Pressure Reduction Schedule using steps 1 through 5 as shown on Fig. 3-5. 1

After calculating the total tubing or work string volume in barrels or strokes, as indicated in the wait-and-weight calculations above, record it on the pressure reduction schedule.

2

Determine and record the number of strokes or bbls from 0 to Total Strokes using the formula given in step 2.

3

Record the ICP that was predetermined in the wait-and-weight calculations above.

4

Record the FCP that was predetermined in the wait-and-weight calculations above.

5

Determine and record the circulating pressures from ICP to FCP using the formula in step 5.

Figure 3-5

3-14

Five steps for completing pressure reduction schedule

Well Control for Workover Operations

Additional Considerations for the Wait-and-Weight Method •

Accuracy of readings, especially SITP, is crucial to the success of the kill. A false reading will lead to error in calculating kill weight fluid, which results in circulating the wrong fluid weight around the well.

•

Because of the importance of accurate readings, the WSS should ensure the accuracy of the gauges beforehand and perform the trapped pressure checks described earlier in the lesson.

Well Scenario: Wait-and-Weight Method The following scenario describes a potential use of the wait-and-weight method during workover operations. Fig. 3-6 shows a well shut in on a 10 bbl kick. The pore pressure of the producing zone is 5,200 psi, which is equivalent to 10 ppg at a vertical depth of 10,000 feet. The WSS decided to work the well over with 10.2 ppg brine, thus rendering the well dead during the workover. Through inadvertent dilution, the density of the workover fluid was reduced to 9.5 ppg and pumped into the well, creating an underbalance.

Lesson 3

3-15

Figure 3-6

Well with 10 bbl kick

The wellbore hydrostatics and shut-in pressures for this example are as follows: •

Annular hydrostatic pressure = 5,048 psi, yielding SICP of 152 psi

•

Work string hydrostatic pressure = 4,940 psi, yielding SITP of 260 psi

•

Pump output = 0.070 bbl/stroke

At the beginning of the day, the driller took SCRPs at various pump rates and recorded the rates and observed pressures with a 10.2 ppg fluid in the well.

3-16

Well Control for Workover Operations

Following the kick, the WSS selected the rate of 2 bpm as the kill rate. When the well was brought on choke, the choke operator held the casing pressure constant at approximately 150 psi. At 2 bpm the pump pressure stabilized at 950 psi, which was the observed ICP. (Remember, there is 9.5 ppg fluid in the well, not 10.2 ppg fluid, so the ICP must be observed rather than calculated with the standard equation.) The FCP is a known value. It equals the SCRP previously taken before the fluid was diluted and the kick taken. Therefore, a pumping schedule (Fig. 3-7) can be generated from the observed ICP and the known pressure at the selected kill speed of 2 bpm, which was 750 psi with 10.2 ppg fluid.

Figure 3-7

Circulating pump pressure schedule

Constant Pump Pressure Method Use the constant pump pressure method in situations in which the hydrostatic pressure of the work string fluid is sufficient to balance the formation pressure— that is, when the fluid weight does not have to been increased. Evidence of this is when SITP = 0 (and not because tubing is blocked with a BPV). The method is used in mechanically induced kicks, for example, when gas is swabbed into the wellbore.

Lesson 3

3-17

Unlike the wait-and-weight method, this method does not require a pump pressure reduction schedule, thus the name “constant pump pressure,” which describes what is to be done with the pump pressure. Using the choke, hold the pump pressure constant at the observed ICP and circulate the influx from the wellbore. It is prudent to circulate at least one “bottoms up” (one annulus volume). Circulation can be longer if desired.

Constant Pump Pressure Procedures Follow these steps to circulate a kick out of the wellbore with the constant pump pressure method: 1

Line up the manifolds and pump to circulate fluid down the tubing and take returns from the annulus.

2

Bring pump to kill speed while holding the annulus pressure constant with the choke, thus establishing ICP on the tubing gauge. (The ICP can also be calculated using the same method as in the wait-and-weight method. The observed reading, however, is preferred to the calculated value.)

3

Continue to circulate, using the choke to hold pump pressure constant until the influx is removed from wellbore (or longer, if desired).

4

Shut down and check for pressures and flow.

Fig. 3-8 shows the pressure profiles of the constant pump pressure method. Similar to the wait-and-weight method, the process control is the pump pressure, which is controlled with the choke.

3-18

Well Control for Workover Operations

Figure 3-8

Pressure profiles for constant pump pressure method

Reverse Circulation Method The reverse circulation method, or “reversing out” a kick, involves pumping down the annulus and taking returns from the tubing. Reversing is fairly common in workover operations for a variety of reasons: •

Time can be saved if only a “bottoms up” circulation is required. Bottoms up through the tubing is usually a much smaller volume than bottoms up through the annulus. Reversing is sometimes called the “short way” and normal circulation the “long way” because of this fact.

•

Since the tubing bore is smaller, fluid velocities are higher, and the capacity of the fluids to carry solids, scale, and debris is improved.

•

Due to the circulation path, the high pressures due to gas expansion are exposed to the tubing rather than the casing. The tubing is usually better equipped to handle these pressures.

In reverse circulation, the flow path lineup and the pump-start procedure are quite different from those of forward circulation. These differences are indicated in the reverse circulation procedure below.

Lesson 3

3-19

Reverse Circulation Procedures 1

Line up manifold and pump to circulate fluid down annulus and take returns from tubing.

2

Bring pump to kill speed while holding tubing pressure constant with choke. This establishes ICP on casing gauge.

3

Continue to circulate, using choke to control casing pressure.

Even when circulating liquids only, additional “invisible” pressure is being exerted downhole when reversing in most wellbore geometries whereby the tubing bore is smaller than the annulus. (For a review, see “Friction Pressure” on page 2-4 and “Dynamic Pressure Analysis” on page 2-34.) If the well has open perforations that are exposed, whole fluid can be pumped into the formation, causing formation damage. If the excess pressure is high enough, formation fracture damage can occur as well. Using a lower pump speed will reduce dynamic bottomhole pressure. If available, a fluid hydraulics program should be used to validate the choice of pump speed. Reversing Gas Kicks As long as the kick fluid is liquid (or primarily liquid), risks are minimal. If the kick is predominantly gas, it is important to be aware of the potentially rapid change in surface pressures and the equipment used when the reverse procedure is implemented. Fig. 3-10 through Fig. 3-15 illustrate the differences between normal and reverse circulation where a gas kick is concerned. The left side of each figure illustrates normal circulation, and the right side illustrates reverse circulation. For this analysis, temperature and resulting gas compressibility will be ignored.

3-20

Well Control for Workover Operations

Figure 3-9

Lesson 3

Well diagram with gas kick

3-21

58 bbl (tubing volume) have been pumped. The influx has expanded based on the reduction in hydrostatic pressure above the gas. With this expansion comes a reduction in the annular hydrostatic pressure, resulting in an increase in casing pressure. 20 bbl (annular volume) have been pumped. The influx has been removed from the casing and now resides in the tubing. Static casing pressure is now 0 psi. The static tubing pressure reflects the vast change in tubing hydrostatic pressure due to the considerable vertical length occupied by the gas.

Figure 3-10 Reversing a gas kick: stage 1

3-22

Well Control for Workover Operations

A total volume of 75 bbl has been pumped. The influx has further expanded, and the decreased annular hydrostatic pressure has resulted in a casing pressure of 679 psi.

40 bbl have been pumped. Considerable gas expansion has taken place in a relatively short period of time requiring extensive choke adjustments. Take note of the change in tubing pressure between this drawing and the previous one.

Figure 3-11 Reversing a gas kick: stage 2

Lesson 3

3-23

A total volume of 100 bbl has been pumped. The expanded influx and decreased annular hydrostatic pressure has resulted in a casing pressure of 848 psi.

43.5 bbl have been pumped. Clearly seen in this diagram is the rapid expansion of the gas as it approaches the surface. And along with this expansion and reduction in annular hydrostatic pressure is a rapid increase in required choke back pressure in a relatively short period of time.

Figure 3-12 Reversing a gas kick: stage 3

3-24

Well Control for Workover Operations

A total volume of 125 bbl has been pumped. The expanded influx and decreased annular hydrostatic pressure has resulted in a casing pressure of 1,114 psi.

78 bbl have been pumped. Both the tubing and annulus are now full of fluid and the well is dead

Figure 3-13 Reversing a gas kick: stage 4

Lesson 3

3-25

A total volume of 148 bbl has been pumped. The influx has expanded from its initial volume of 20 bbl to now occupying 65.08 bbl of space in the annulus. The casing pressure of 1,537 psi is the result of the decrease in annular hydrostatic pressure due to this expansion.

Well dead.

Figure 3-14 Reversing a gas kick: stage 5

3-26

Well Control for Workover Operations

Figure 3-15 Pressure profiles for reversing a gas kick

Pressure Profiles When Reversing a Gas Kick The high level and rapid change in tubing pressure when reversing a gas kick, as seen in Fig. 3-15, presents safety concerns. The use of the proper equipment, which has been installed correctly, function tested, and pressure tested (where applicable) is crucial. For more information, see “Reversing Gas Kicks” on page 7-15. By comparison, if the kick is a liquid (oil or water), there will be no severe loss of tubing hydrostatic pressure because liquids do not expand as gas does; thus they do not create the dramatic increase in tubing pressure. Realistically, it is rare to have a liquid hydrocarbon influx enter the well without some associated gas. Therefore, on the rig always expect some increase in tubing pressure when reversing. The change just may not be as dramatic as with a fullblown gas influx.

Lesson 3

3-27

Noncirculating Well Control Procedures The following procedures are regarded as noncirculating procedures because, even though a pump is used, there is not a full circulating path for the fluids—that is, fluid is not pumped completely down the tubing and back up the annulus or vice versa. These procedures include the bullheading method, the constant tubing pressure method, the volumetric method, and the two types of the lubricate-andbleed method.

Bullheading Bullheading is a means of killing a producing well in which produced fluids are pumped back into the producing formation and the tubing is filled with kill fluid at the same time (Fig. 3-16). It is not a constant bottomhole pressure method; the crew intentionally exceeds the injectivity limits of the formation while making every effort not to exceed the fracture limits. It is the simplest of the well kills and probably the most common worldwide for workover procedures. Prior to performing a bullheading operation, several factors should be considered: •

Formation pressure. The best source for this information is a recent bottomhole pressure (BHP) survey.

•

Condition of the perforations (perfs).

•

3-28

•

If the perfs are blocked and will not readily accept fluid, unacceptably high pressures can be created at the perfs, leading to possible formation or cement failure.

•

The presence of sand or junk in the system may plug or block perfs, preventing the fluid from even reaching them.

•

Nearby zones that have previously been cement “squeezed” may impose pressure limitations on the current operation. Every effort should be made to obtain formation fracture information, permeability data, and historical data from the well regarding previous workovers (see “Planning and Preparation” on page 8-2).

The condition of the tubulars, both tubing and casing. Tubing-to-annulus communication indicates leak paths. You should also review previous workover

Well Control for Workover Operations

data to identify any de-rating of the casing or tubing pressure limits due to wear or damage. •

The condition and working pressure of the wellhead.

•

The presence or absence of in-situ annular fluid, called packer fluid, which reacts against applied internal tubing pressure. The hydrostatic pressure of the annular fluid (called “backup”) has a great impact on tubing burst. For more information on in-situ packer fluids, see “Types of Workover and Completion Fluids” on page 5-2.

•

Formation compatibility with kill fluid (unless the zone is to be abandoned).

Figure 3-16 Bullheading

Pre-recorded Data Required for Bullheading •

Lesson 3

Formation pressure, preferably from a recent BHP survey

3-29

•

Desired overbalance, provided by kill fluid

•

Perforation depth, measured and vertical

•

Fracture pressure—estimate of the formation fracture strength

•

Tubing specifics: ID, length, end of tubing (EOT), burst pressure rating, percent wear, tubing condition

•

Annular fluid backup—the presence or absence of fluid in the annulus and its density

•

Rathole: ID and measured length

•

Pump size—liner, stroke, and efficiency data or actual output from test

•

Surface pressures: SITP, SICP, and pressure on casing strings (if any)

•

Wellhead working pressure

Bullheading Calculations Complete the following calculations in preparation for the bullheading procedure (see “Bullheading Scenario” on page 3-32).

3-30

•

Volume To Pump. This includes both the tubing volume and the annular space below the packer (if any exists).

•

Kill Weight Fluid. The density is based on the formation pressure of the zone to be killed. Density is generally calculated to include a 100–300 psi overbalance safety margin (see Fig. 2-14.)

•

Fracture Pressure. Formation fracture pressure is used to determine surface pressure limits throughout the operation.

•

Working Tubing Burst. Standard practice is to downgrade to 80% of the published tubing burst pressure. If corrosion or wear is known to be greater than 20% of the tubing wall thickness, use a lower number. A caliper survey is used to determine this.

•

Maximum Tubing Pressure (mechanical limits). These calculations consider the tubing burst rating and total hydrostatic pressure in the tubing prior to the operation and when the operation is completed, both with and without the presence of backup fluid in the annulus. The equations to calculate these limits are shown below.

Well Control for Workover Operations

Maximum Initial Tubing Pressure (no backup) = Working Burst Pressure - (Tubing Hydrostatic Pressure) = Working Burst Pressure - (Formation Pressure - SITP) Maximum Final Tubing Pressure (no backup) = Working Burst Pressure - Kill Fluid Hydrostatic Pressure Maximum Initial Tubing Pressure (with backup) = (Working Burst Pressure - Formation Pressure) + Backup Hydrostatic Pressure Maximum Final Tubing Pressure (with backup) = (Working Burst Pressure - Kill fluid Hydrostatic Pressure) + Backup Hydrostatic Pressure •

Maximum Tubing Pressure (formation limits). Limiting this parameter protects the formation, initially with light fluid in the string and finally with kill fluid in the string. The equations to calculate these limits are shown below.

Maximum Tubing Pressure (Formation Limits) = [Formation Fracture Strength (ppg) - Initial Fluid Weight in Tubing*] × Formation TVD × 0.052 = [Formation Fracture Strength (ppg) - Final Fluid Weight in Tubing **] × Formation TVD × 0.052 * before bullheading; formation fluid in tubing ** after bullheading; kill fluid in tubing

The calculations for either maximum tubing pressure (mechanical limits) or maximum tubing pressure (formation limits) can be the limiting factor on bullheading pressure. The pressure schedule in Fig. 3-17 illustrates both the

Lesson 3

3-31

mechanical and fracture limits on tubing pressure plotted against strokes or barrels as the tubing is displaced with kill fluid. Carefully review the bullheading scenario in the following section to enhance your understanding.

Figure 3-17 Bullheading pressure profile

Bullheading Scenario This scenario uses actual well data to illustrate the required calculations and graph plotting required in preparation for bullheading. Well Information

3-32

•

Depth of formation/perfs: 10,170 ft

•

Formation pressure equiv.: 8.8 ppg

•

Formation frac equivalent: 13.8 ppg

•

Tubing 4 1/2", N80 Vam: 0.01521 bbl/ft to 10,170 ft

•

Rathole: 6.538" ID, Length = 80 ft

•

Tubing burst (new): 8,430 psi

Well Control for Workover Operations

•

Shut-in tubing pressure: 3,640 psi

•

Gas gradient: 0.1 psi/ft (1.9 ppg)

•

Kill fluid overbalance: 150 psi

•

Measured pump output = 0.058 bbl/stk

•

Fluid backup: assume none

Calculations for Bullheading Pressure Schedule 1

Calculate kill weight fluid. Kill Weight Fluid = 8.8 + (150 ÷ 10170 ÷ 0.052) = 9.1 ppg

2

Calculate the maximum tubing pressure (formation limits). Initial limit (tubing full of gas) = (13.8 - 1.9) × 10,170 × 0.052 = 6,293 psi Final limit (tubing full of kill fluid) = (13.8 - 9.1) × 10,170 × 0.052 = 2,486 psi

3

Calculate the working tubing burst limit. Working limit = 0.8 × 8,430 = 6,744 psi

4

Calculate Maximum Initial and Final Tubing Pressure (mechanical limits, no backup). Maximum Initial Tubing Pressure = [6744 - (8.8 × 10,170 × 0.052)] + 3,640 = 5,730 psi Maximum Final Tubing Pressure = 6,744 - (9.1 × 10,170 × 0.052) = 1,932 psi

5

Calculate bullhead volume/pump strokes. Tubing: 10,170 × 0.01521 bbl/ft = 154.69 bbl Rathole: 80 × (6.5382 ÷ 1029.4) = 3.32 bbl Total bbl = 158.01 = 158 bbl Total strokes = 158 ÷ 0.058 = 2,724 strokes

6

Lesson 3

Plot SITP, Maximum Tubing Pressure Formation Limits (called the frac line), Maximum Tubing Pressure Mechanical Limits on Y axis against strokes on X axis (Fig. 3-18).

3-33

Figure 3-18 Bullheading pressure schedule

Note that in this example, the upper limit on tubing, or pump, pressure is controlled by tubing burst (the line between 5,730 and 1,932 psi). The frac line is not the limiting case. Remember, the conservative assumption was made that there is no hydrostatic backup fluid behind the tubing. In an older well or a well with no available information, this would be an appropriate assumption. It has the effect of lowering the maximum pump pressure allowed. If it is known that backup fluid does exist and its density is known, the calculations change and the graph will take on a different shape, with the upper limit being the frac line. Bullheading Procedure for Scenario After the schedule is constructed, it is used as a tool to monitor and limit the pumping pressure. One important note: bullheading does not have a return fluid path. Therefore there is no place to put a choke, so a choke cannot be used to control pressure. The one tool available is pump speed. Pump speed is adjusted to stay inside the safe pumping range on the graph. It is helpful to plot observed pump pressure directly on the graph as the kill fluid is being pumped (see the green line in Fig. 3-19). The plotted points show a visual 3-34

Well Control for Workover Operations

trend line that indicates when the limit line is being approached. The pump speed can be reduced before the plotted pump pressure line reaches the limit line, thus avoiding exceeding the pressure limit.

Figure 3-19 Plotted bullheading pressure schedule

Bullheading Considerations When using bullheading to kill a well, make sure you consider the following:

Lesson 3

•

Hold a pre-job meeting to discuss operational and safety concerns. Conduct risk analysis and hazards analysis.

•

Install a tested safety valve in the work string and connect the pump in line to the safety valve.

•

Protect all pressurized parts of the system by relief valves that have been tested before the job begins.

•

Make sure that the fluid to be used to bullhead is compatible with the formation and as solids free as possible to prevent pore throat blockage.

3-35

•

Clearly mark pressurized lines and properly secure them. Brief personnel on the location of these lines and instruct them to stay clear while bullheading is in progress.

•

Be prepared for the well kill to require several attempts. Pressure may not remain at zero even though a precalculated amount has been pumped. Additional fluid volume should be available on location.

•

Measure and record the amount of fluid pumped.

•

If using brines as kill fluid, use the agitators in the rig tanks to stir the fluid often. This mixing assists in keeping the salt in solution, thus maintaining density. The same would be true if using mud (e.g., for a zone to be abandoned). Agitation keeps the barite in suspension.

•

If initial casing pressure is extremely high, it may be wise to bullhead the annulus first or consider simultaneously bullheading the tubing and the annulus.

Casing Pressure Increase Whenever bullheading is performed in a completion with a packer in place, the WSS must pay attention to the casing pressure reading and must ensure that the crew fully understands the importance of reporting this immediately. Increases in casing pressure could be due to thermal expansion caused by pumping liquids down the tubing or by holes in tubing, leaking tools, sliding sleeves, gas-lift valves, safety valves, and packer seals. The presence of, or an increase in, casing pressure can have dire consequences. Excess pressure applied to the top cross-sectional area of the packer creates a great deal of force—enough to force the packer down the hole and part the tubing (see Fig. 3-20). Additionally, the excess pressure in the annulus creates a situation in which the casing burst pressure limit can be reached or exceeded, not necessarily at the surface but downhole. Should casing pressure appear or increase, try to bleed the pressure to its previous value and monitor it closely. Casing pressure that continues to increase and will not bleed down is cause for concern, and the operation should be halted until the source of the increase is determined and the situation remedied. For more information, see “Unexpected Changes in Gauge Readings” on page 7-22.

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Well Control for Workover Operations

Figure 3-20 Casing pressure increase during bullheading

Gas Channeling Gas channeling can occur during a bullheading operation in gas wells or oil wells with a high gas-oil ratio (GOR), especially if the kill fluid lacks sufficient viscosity and the pump rate is slow. In that case, gas may channel up the tubing faster than it is being forced down the tubing through pumping (Fig. 3-21). Generally, after pumping the calculated volume and shutting down the pumps, the tubing pressure is 0 psi and the well is dead. There are times, however, when SITP drops to 0 psi and the well appears to be dead, but after 30 minutes or so, the SITP starts to increase. This increase often indicates gas channeling. It is particularly troublesome in highly deviated wells. One known remedy to this situation is to pump a viscous pill such as XC polymer ahead of the kill fluid to minimize the gas channeling. As always when

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considering the use of any fluid, take into account the fluid’s compatibility with the production zone.

Figure 3-21 Gas channeling

Cold Bullheading “Cold bullheading” is a term used to describe bullheading when the kill fluid is at a lower temperature than the wellbore. The temperature difference generates thermal stresses that would normally result in shortening the tubing. But since the tubing is locked into the completion and its length cannot change, an upward tensile force is created in the tubing, which pulls upward on the packer and creates a force that may unseat it. Using computer software, you can determine the magnitude of this force and apply a balancing force downward on the packer by pressuring the annulus to the amount calculated by the computer program.

Procedures for Controlling Gas Migration The two modes of gas behavior in the wellbore were explained in an earlier lesson: gas expansion, where gas is free to expand normally (as it does in constant bottomhole pressure kill procedures), and gas migration, where gas migrates up a 3-38

Well Control for Workover Operations

shut-in or blocked wellbore and does not or cannot expand. For a review, see “Gas Behavior in the Wellbore” on page 2-41. The WSS should know these characteristics of gas migration: •

It can occur when the well is shut in with gas present (either when the well is shut in intentionally or the flow path is mechanically plugged or blocked).

•

It is indicated by a uniform increase in SICP and SITP.

•

If uncontrolled, it increases pressures everywhere in the wellbore.

•

If ignored, these increased pressures can cause formation damage and loss of whole fluid into the perfs.

•

It occurs rapidly in the clear workover fluids typically used (research indicates speeds of 4,000-6,000 feet per hour).

There are two recognized methods of dealing with migration, or “allowing expansion,” so to speak: the constant tubing pressure method and the volumetric method (also called the “stairstep” method). These methods are used to control gas migration when it is not possible to circulate or bullhead the well. They can be used temporarily while operations are ongoing to get in a position where the well can be circulated or bullheaded. (Unplug the tubing, fix the pumps, shift a sliding sleeve, or create a flow path in some way.)

Constant Tubing Pressure Method The constant tubing pressure method is the simpler of the two methods; its name describes what is done. It is based on the following assumptions: 1

There is communication between the tubing and the choke located on the annulus.

2

The tubing pressure can be read.

This procedure can be used to control gas migration while mixing kill fluid or making other preparations for a circulating kill procedure. Procedure for Constant Tubing Pressure Bleed Method

Lesson 3

1

Allow SITP to increase by a safety margin of 50-100 psi (which prevents further influx due to overbleeding with choke). This is called the lower limit.

2

Allow SITP to increase an additional 50-100 psi. This is the upper limit.

3-39

3

Using the choke, bleed the annulus until the tubing pressure drops down to the lower limit. Remember the time lag (see Important Note below).

4

Repeat steps 2 and 3, keeping the tubing pressure between the lower and upper limits as long as desired or until another procedure is implemented. Important Note: There is a time lag between opening the choke and seeing the pressure drop on the tubing gauge. The pressure “signal” must travel down the annulus and up the tubing to the tubing gauge, which is thousands of feet away. The recommended procedure is to open the choke until the desired drop is seen on the casing gauge, then close the choke and wait until the change appears on the tubing gauge.

In the long term, the casing gauge reading will not stay constant the way the tubing gauge does (the WSS should not use the choke to make it so!). With successive bleed cycles, the gas is continually expanding as it rises up the annulus. If you do not have a full understanding of why the casing pressure must increase in this case, review “Gas Behavior in the Wellbore” on page 2-41.

Volumetric Method This procedure accomplishes the same objective as the constant tubing pressure method in allowing gas expansion, but it uses a different process control. This method is used when there is no tubing communication. Since tubing pressure cannot be read, the process must be controlled with the casing pressure and the volume of fluid bled from the annulus. There must be a calibrated tank on the rig located downstream of the choke capable of reading in as small as 1/2 bbl increments. (For a review of tank calibration, see “Fluid Tank Volumes” on page 2-24.) Procedure for Volumetric Method 1

Select a safety margin and a range. Recommended margin: 100 psi; range: 100 psi.

2

Calculate hydrostatic pressure (Hp) per bbl fluid in the upper annulus. Hp per bbl (psi/bbl) = Fluid Gradient (psi/ft) ÷ Annular Capacity Factor (bbl/ft)

3

Calculate volume to bleed each cycle. Volume to bleed (bbl/cycle) = Range (psi) ÷ Hp per bbl (psi/bbl)

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Well Control for Workover Operations

4

Construct casing pressure vs. volume to bleed schedule. Fig. 3-22 illustrates the volumetric calculations and construction of the volume to bleed (stairstep) schedule.

5

Allow SICP to increase by margin without bleeding.

6

Allow SICP to increase by range without bleeding.

7

Maintaining SICP, bleed small volumes of fluid into tank until calculated volume in step 3 is bled. Repeat steps 6 and 7 until gas is at surface or another procedure implemented. Important Note: During the procedure, it is critical to hold SICP constant while bleeding fluid. The stairstep schedule is shown in Fig. 3-22. The bleeding is done on the flat part of the stairstep—that is, the SICP is not to increase or decrease. The choke should not be opened more to speed up the bleeding process (which lowers SICP below the line) or another kick will result. Patience is required: the bleed for the first stairstep may take several hours (depending on well depth and type of wellbore fluid).

Figure 3-22 Volumetric calculations and pressure schedule

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The question often arises, “How long should this procedure be carried on?” Remember that the goal is to control gas migration and allow expansion. If the gas influx reaches the top of the well during the stairstep schedule, the procedure is over: gas migration has been controlled. (This is evidenced by the sound of gas flowing across the choke and a stable SICP when the well is closed in.) Do not open the choke at this point and bleed gas off the well. This will reduce bottomhole pressure and most likely result in additional influx. It will then be necessary to create yet another pressure schedule and repeat this rather timeconsuming procedure. Removing gas from the top of a well (at constant BHP) requires lubricate-and-bleed procedures, which are explained in the next section.

Procedures for Removing Gas from a Wellbore (Lubricate-andBleed Procedures) The lubricate-and-bleed procedure is used to remove gas from the top of a wellbore at constant bottomhole pressure while preventing additional influx from the formation. There are two types of lubricate-and-bleed (commonly called “lubrication” and “bleed and feed”)—the volume method and the pressure method. These procedures are to be used whenever a conventional circulating method is not feasible. They can be used following the volumetric method (see “Volumetric Method” on page 3-40). They can also be used on production wells to remove persistent casing pressure that soon returns after attempts bleed it off by simply opening valves. In these procedures, the gas is bled off and replaced with fluid in calculated steps. Fluid is pumped into the annulus, a waiting period is allowed for the fluid and gas to separate, bleed calculations are done, and, finally, gas is bled off the annulus, reducing the casing pressure by the calculated amount. The procedure can be summarized in four steps: pump, wait, calculate, bleed (then repeat).

Volume Method—Lubricate-and-Bleed The volume method is so named because pressure is bled off in amounts calculated from the measured volume of fluid pumped in. Fluid pumped in is measured (from a calibrated tank), and bleed-off calculations are based on the hydrostatic pressure of that measured volume (see Fig. 3-23).

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Well Control for Workover Operations

Procedure for the Volume Method—Lubricate-and-Bleed 1

Pump into the annulus of the closed-in well to increase casing pressure by desired range. Recommended range = 100 psi

2

Allow time for fluid to fall through the gas (usually 10-15 minutes).

3

Measure the tank and calculate the hydrostatic pressure increase in the wellbore. Hydrostatic pressure increase = Volume Lubricated (bbl) × Hydrostatic Pressure per bbl Note: Hydrostatic pressure per bbl = gradient of fluid pumped (psi/upper annulus factor). See the calculations for Upper Annulus Capacity Factor (bbl/ft) in Fig. 2-8.

4

Bleed dry gas from choke to reduce casing pressure by the range plus the hydrostatic pressure increase.

5

Repeat steps 1 through 4 until gas is removed.

Fig. 3-24 shows a sample lubrication problem along with a worksheet to organize data and calculations.

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Figure 3-23 Well diagram for volume method

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Well Control for Workover Operations

Figure 3-24 Sample well and volume method lubrication worksheet

Pressure Method—Lubricate-and-Bleed The four steps in this method are identical to those in the volume method: pump, wait, calculate, bleed. The difference is that the pressure method does not require volume measurements, which changes the calculations. The calculations for the bleed-down pressure are based on pressure readings, both before pumping and after, as shown in the following equation: P3 = P12 ÷ P2 P1 = SICP before pumping P2 = stabilized SICP after pumping P3 = the pressure to bleed down to Fig. 3-25 provides an example of the pressure method and a worksheet.

Lesson 3

3-45

Figure 3-25 Well diagram and pressure method lubrication worksheet

A feature of this lubrication method (other than the obvious simplicity of the calculation) is that if the formation is taking fluid, the calculation of P3 is “self adjusting.” Remember, the stabilized pressure reading after pumping is used for the P2 value. If the formation perfs take fluid, the gauge reading will fall until the well is in equilibrium once again. In the example in Fig. 3-25, for instance, if the pressure fell off from 1,100 to 1,080 after 10 minutes and stabilized, you would simply change P2 to 1,080 and redo the calculation. 1,0002 ÷ 1,080 = 926 psi (the new P3). Bleed to 926 psi rather than 909, as shown. At the beginning of the next cycle, pump in again until 1,026 psi is reached. Again, wait for the pressure to stabilize. If it falls on this cycle, it confirms the formation is taking fluid and cannot support an additional 100 psi. Consider changing the pressure increase (the range) to 50 psi and see whether the well will support it. It is a simple matter to change the numbers on the worksheet. Important Note: This method is not valid for underbalanced kicks (where kill fluid must be pumped). The assumptions used to develop the equation P3 = P12 ÷ P2 are valid only if all the casing pressure is due to the presence of gas in the annulus and not partially due to fluid underbalance. A test would be

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Well Control for Workover Operations

as follows: if all the gas is removed from the annulus, is the SICP be zero? If the answer is yes, this method can be used. If no, use the volume method.

Selection of Well-Kill Methods The following well-kill techniques have been presented in this lesson: •

Bullheading

•

Forward and reverse circulation

•

Volumetric method

•

Lubricate-and bleed—pressure method

•

Lubricate-and-bleed—volume method

•

Constant pump pressure method

•

Wait-and-weight method

This section will provide guidelines and considerations to assist the WSS in the selection of appropriate kill methods, both for the initial kill of the live well and for subsequent kills that become necessary during the workover

The Initial Well Kill Bullheading Bullheading followed by circulation is by far the most common means of killing a producing well. During early stages of the workover, this procedure has the following characteristics:

Lesson 3

•

It is simple.

•

It causes an early pressure reduction on the tubing.

•

It forces the contents of the tubing (hydrocarbons from the formation) back into their source.

•

It should not cause reservoir damage, provided fracture limits are respected (see “Bullheading Scenario” on page 3-32).

3-47

Later in the workover, depending on the operation, the tubing may contain spent acid, cuttings, and trash from milling or fishing operations. Bullheading at this stage would be undesirable. The following situations limit or prohibit bullheading: •

Plugged perforations

•

Tubing that is plugged with sand, scale, paraffin

•

Tubing that is not intact

•

Unexplained, unbleedable annulus pressure (indicating a possible tubing or packer leak)

Long-Way Circulation (after Bullheading) This procedure has the following characteristics: •

It is the most common method of killing the well.

•

It exposes the formation to less friction pressure than reverse circulation (at the same pump speed).

•

It will not expose the formation to “heavy” or “dirty” packer fluid. (If the well is depleted, the packer fluid may be considerably overbalanced to the current formation pressure. In addition, the packer fluid in an old well will have undesirable solids such as corrosion products, deteriorated inhibitors, or crystallized salts and scales.)

•

It may be inefficient and require more circulation time if it involves displacing heavy, dirty packer fluid with lighter, clean completion fluid.

•

It will create pressure on the upper casing if circulating up any residual gas (e.g., gas below packer or residual tubing gas). This pressure could be a problem if the casing is deteriorated.

Reverse Circulation (after Bullheading) This procedure has the following characteristics:

3-48

•

It produces lower pressures on upper casing than long-way circulation (if pressure is a concern).

•

It displaces fluids more efficiently due to higher tubing velocity.

Well Control for Workover Operations

•

It exposes the formation to more friction pressure than long-way circulation (at same pump speed).

•

It is acceptable with bad packer fluid in the annulus if an isolation plug can be set downhole to block fluid loss into perfs.

•

It requires “spearheading” or leading the tubing displacement with a viscous pill such as HEC to reduce fluid losses later during reversing.

Lubricate-and-Bleed Methods (Pressure and Volume) These methods are better than bullheading for killing large-bore tubing on highvolume gas wells. Much of the fluid can channel past the gas when trying to bullhead in large tubing. The lubricate-and-bleed pressure method is better for high-volume gas wells as it uses pressure as a control and not volume pumped. A portion of the volume may have been lost into perforations. (For a review, see “Pressure Method—Lubricateand-Bleed” on page 3-45.) The lubricate-and-bleed methods are applicable in a well with parted tubing and gas at surface.

Subsequent Well Kills during the Workover The following provides guidelines for choosing the appropriate well-kill method for a given situation.

Swabbed Kick The constant pump pressure method (identical to the first circulation of the widely known “drillers” well-kill method) is most appropriate for controlling a swabbed kick. This method can be used with either forward or reverse circulation. Reversing has the benefit of taking the least time. If the kick were on bottom, “bottoms up” would involve only the tubing volume.

Kick with Check Valve in Work String If the well has a history of trapped pressure behind sand plugs, wax plugs, or ice, the standards call for use of a check valve installed in the work string to prevent flow up

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the string. Forward circulation is required in this situation since the check valve blocks the reverse circulation path.

Underbalanced Kick A underbalanced kick is not as common in workovers as it is in drilling, but if the workover program called for deepening or sidetracking a well into a new formation, the situation may occur. Schlumberger IPM recommends the “drillers” method in this case since circulation is immediate and the offending influx is removed from the hole quickly. Following the influx removal, a second circulation with kill weight fluid will be necessary to kill the well.

Kick with Work String out of the Hole These kicks can occur while doing wireline work, logging, and similar operations. If the invading kick fluid is gas (evidenced by increasing shut-in pressure over time), the volumetric method is appropriate (for a review, see “Volumetric Method” on page 3-40).

Gas at Surface—Work String out of the Hole If a well was shut in at night without a work string, any invading wellbore gas would probably be at the surface by daylight. There would also be gas at the surface after completing the volumetric method. The lubricate-and-bleed procedures are the most appropriate well-kill methods in these situations. If there are open perforations that are capable of taking a portion of the lubricated volume, use the pressure method (see “Pressure Method—Lubricate-and-Bleed” on page 3-45).

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Well Control for Workover Operations

4 CAUSES AND WARNING SIGNS OF KICKS Lesson Overview Understanding the causes and warning signs of kicks can help the WSS and crew prevent them from occurring or, if they do occur, at least minimize their effect. This lesson presents the most common causes of kicks during workover operations as well as kick warning signs and recommended actions for handling a kick if it does occur.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to: •

Describe the most common causes of kicks during workover operations.

•

Describe the kick warning signs and the available surface indicators of kicks in workover operations.

•

Describe the actions you should take when you observe a warning sign.

Causes of Kicks Most kicks can be eliminated safely and effectively if the WSS and crew monitor operations carefully and understand the necessary actions that should be taken in the event of a kick. The best option, however, is preventing kicks. Knowing what Lesson 4

4-1

causes an influx of undesired well fluids into the wellbore is the first step in preventing kicks. Known causes of kicks include: •

Insufficient fluid density or weight

•

Swabbing

•

Surging

•

Failure to fill hole when pulling tubing

•

Failure to monitor and maintain correct hole fill volume during tripping

•

Failure to circulate after shut-in periods

•

Loss of fluid downhole

•

Disabled alarms

Insufficient Fluid Density (Weight) Fluid density, or weight, affects the hydrostatic pressure in the hole. Using the hydrostatic pressure to control formation fluids from entering the wellbore is primary well control. Primary well control can be lost when the fluid weight becomes insufficient to balance the formation pressure. Fluid weight can become insufficient for the following reasons:

4-2

•

There is incorrect information about actual bottomhole pressure.

•

Rainwater has diluted the workover fluid, lowering its weight.

•

The fluid scale (mud balance) used to measure density is inaccurate.

•

The fluid scale (mud balance) is used improperly.

•

Small influxes from downhole have diluted the workover fluid that is recirculated downhole. Small influxes of formation fluids can occur without being considered a kick. They can dilute the recirculating wellbore fluid to the point where it is insufficient to balance formation pressure and thus can cause a kick. Returning fluid must be weighed regularly and action taken to restore correct density to the fluid being recirculated.

•

Fluids in the surface system have intermingled because of leaking valves and improper lineup.

•

Excessive or careless use of water on or around fluid tanks has diluted the workover fluid. Well Control for Workover Operations

•

The crew has switched pump suction to the wrong fluid tank, and the fluid circulating downhole is not dense enough to control the well.

•

The tank has not been sufficiently agitated to prevent weighting material from settling out, thus lightening the fluid that is circulated downhole.

•

The workover fluids have undergone thermal expansion (Fig. 5-1).

•

The workover fluids have encountered a gas bubble or other formation fluids blocked by a bridge or packer. When washing through sand bridges or milling over packers, you can encounter higher pressure under the bridge or packer. Pressure below a packer or sand bridge may be much greater than the workover fluid hydrostatic pressure above it at that depth. This imbalance can be very acute when a gas bubble at formation pressure migrates up the tubing and rests under the sand bridge. When the bridge is washed away or the seal is broken, the gas and workover fluid swap places as the gas rises and expands rapidly, causing a sharp increase in flow, possibly unloading the tubing and allowing another kick from the formation.

Swabbing Swabbing is defined as pulling formation fluids into the wellbore by mechanical action, even in the presence of primary well control. The string and what is attached to the end of it (packers, rod pumps, and squeeze tools) can act like a long pump plunger and draw formation fluids into the wellbore. Swabbing is likely when:

Lesson 4

•

Clearances between the string and the wellbore are small. These small clearances occur when pulling packers on the tubing string or during concentric workovers when a small tubing work string is pulled out of production tubing. Small clearances create a high suction pressure on the formation.

•

High-viscosity fluids are used in workovers. The higher the viscosity of the fluid, the more resistant it is to flow. As a result, the fluid resists flow upward past moving tools or pipe and causes high swab pressures that pull formation fluids into the wellbore.

•

The work string is plugged and the fluid inside the work string cannot flow through the end of the tubing, so the string acts like a swab.

•

The work string or completion string is pulled too fast for the conditions in the well.

4-3

Surging Surging occurs when the downward movement of the work string creates pressure surges. These surges add to the hydrostatic pressure; the total wellbore pressure may then cause fluid to be forced into fractures or permeable zones. If enough fluid is lost so that the column height drops below that needed for primary well control, an influx can result. Factors that contribute to surging are similar to those for swabbing: •

Small clearances between the string and the wellbore

•

High-viscosity fluids

•

A plugged work string, back-pressure valve, or float in string

•

Excessive running speed when tripping into the hole

Failure to Fill Hole When Pulling Tubing When pulling tubing or a work string from the well, the metal pulled out of the wellbore fluid will cause the fluid level to drop. If the hole is not filled with the proper amount of fluid (of sufficient weight) to compensate for the metal displacement, primary well control will eventually be lost and a kick can result. The WSS must emphasize the importance of keeping the hole filled with fluid of the proper weight at all times and continually monitor the crew’s adherence to this practice. The WSS and crew should use a trip tank to accurately monitor hole volumes during a trip. The hole volumes should also be recorded accurately and correctly on a trip sheet. The trip sheet is illustrated in Fig. 4-1.

Failure to Monitor and Maintain Correct Hole Fill Volume during a Trip Pulling Tubing or Work String Most crews know the hole needs to be filled during a trip, but it is equally important to measure and monitor the amount required to fill it using a trip tank and trip sheet. Any variance from what has been calculated may indicate a kick. If a well is swabbed, the formation fluids pulled into the wellbore take up volume in the wellbore; thus, the amount of fluid needed to replace the metal pulled from the hole will be less than calculated. This difference indicates an influx of fluids in the 4-4

Well Control for Workover Operations

wellbore. Failure to monitor hole fill or to take immediate action when incorrect hole fill is noticed can cause the well to become underbalanced and eventually to flow, even to the point of unloading the wellbore. In the interest of reducing trip times and costs, some crews are encouraged to continue the trip even when the hole fill measurements indicate an unfavorable trend. However, any time and cost savings are negated quickly when a well kicks with the string off bottom, necessitating stripping or snubbing to return the string to bottom.

Running Tubing or Work String When running tubing or a work string into the hole, the string will displace from the hole a volume of fluid equal to its metal displacement value (or equal to its closedend displacement if the tubing bore is blocked with a plug or BPV). If the hole gives back less fluid than is expected, fluid has been lost to some part of the formation. The loss rate may increase until the column height drops and primary well control is lost, resulting in a kick. This can be prevented by monitoring metal displacement during the trip into the well.

Failure to Circulate after Shut-in Periods On daylight rigs, the well is shut in and secured at night. While shut in overnight, a small influx can migrate into the wellbore. When the well is reopened, the influx may go unnoticed since it is too small to cause the well to flow or else the flow is very slight. You must circulate bottoms up at this point to prevent the undetected influx from migrating and expanding while the workover continues. Failure to do so may cause the well to flow, requiring it to be shut in. If the string is off bottom when this occurs, a time-consuming stripping procedure will be necessary to return the string to bottom. For a review of this shut-in procedure, see “Procedure for Shutting In Well for the Night (Daylight Rigs)” on page 3-6.

Loss of Fluid Downhole Some workover fluid can flow into formation perfs and natural fractures because of low or depleted reservoir pressure, the presence of natural fractures, high formation permeability, or excessive fluid overbalance.

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4-5

Disabled Alarms On some workover rigs, there are audible and visual alarms for fluid tank level and return flow increase. Crews sometimes switch off the alarms because they are noisy and annoying or because they go off prematurely when they need to be calibrated. Switching off the alarms takes away a valuable mechanism for the timely detection of a kick.

Warning Signs of Kicks and First Actions The crew must watch for various warning signs that a kick is occurring or conditions are favorable for a kick. These indicators are described below, along with recommended actions to be taken when they are observed. Warning signs include:

4-6

•

Incorrect hole fill volume when pulling tubing or work string

•

Incorrect displacement volume when running tubing or work string

•

Increase in well flow during circulation

•

Pit gain

•

Shows of oil or gas at the surface

•

Cut fluid weight

•

Drilling, milling, or washing breaks

•

Increase in weight indicator reading

•

Well flow with pumps off

Well Control for Workover Operations

Incorrect Hole Fill Volume When Pulling Tubing or Work String When pulling tubing or work string from the well, the crew should use a trip tank system along with a record of calculated vs. measured hole fill. A negative trend on the trip tank record sheet indicates that an influx has entered the wellbore (see Figure 4-1).

Figure 4-1

Sample trip sheet

In the table, the crew is pulling 60-foot stands of 2-3/8" closed-end tubing. The closed-end displacement is approximately 0.0055 bbl/ft or 0.30 bbl/stand. Notice the negative trend on the trip sheet. After 5 stands, the discrepancy was 0.5 bbl. This increased slowly to 5.0 bbls after 50 stands. The well began to flow sometime after

Lesson 4

4-7

50 stands were pulled and had to be shut in. Yet the negative trend was clearly apparent much earlier in the trip. Note: The trip sheet was completed in 5-stand steps for illustrative purposes only. On the rig, readings should be taken and recorded more frequently, especially when retrieving large assemblies from the hole. When a hole does not take the correct hole fill, as seen on the trip sheet, the WSS should instruct the crew to begin returning the string to bottom while watching for well flow. If the well flows, the crew should shut in the well with the posted shut-in procedure. When the string is back on bottom, the well should be circulated, at least bottoms up, to check for the presence of influx. The WSS should ensure that the crew clearly understands what constitutes a negative trend on a trip and what action they should take. If there is any doubt, the WSS should stay on the rig floor, observe the hole fill trend, and be prepared to make the decision to stop the trip and return the string to bottom. When a trip tank system is not available on a rig, hole fill volume must still be monitored and recorded on a trip sheet. The crew fills the hole manually, records the number of pump strokes required, and determines the volume pumped in barrels. This should be recorded on the trip sheet just as if a trip tank were being used.

Incorrect Displacement Volume When Running Tubing or Work String The indicator of incorrect displacement when running pipe can be seen only if a trip tank and trip sheet are used to monitor displacement volume. For example, if a crew runs 3,500 feet of 2-7/8" tubing (6.5 ppf, closed-end), the displacement would be calculated as follows: (6.5 ÷ 2750) × 3,500 = 8.3 bbls If the trip tank records 5.3 barrels returned from the wellbore, the discrepancy is 3.0 barrels (8.3 -5.3). Until proven otherwise, this should be interpreted as an indicator that 3.0 barrels have been lost to the formation. If the formation is taking fluid, primary well control can be lost and an influx can result. When a trend such as this is observed, the string may be surging the well. Slow the tripping speed and observe the trip tank carefully for improvement in the loss rate.

4-8

Well Control for Workover Operations

Always monitor the hole level and be prepared to fill the hole quickly if the fluid level drops out of sight. When a formation takes fluid due to surging, some or all of the fluid will eventually flow back into the wellbore. In drilling operations, this is called ballooning. According to a key well control principle, it is impossible for the formation to give back more workover fluid than it took in during the surge. Any excess amount of fluid is influx and must be treated as such. The crew should record the amount of workover fluid lost during a surge so they will know when a kick is beginning. Many well control incidents have resulted because the crew assumed incorrectly that the formation was ballooning. Important Note: When tripping in the hole, the WSS should make sure that the crew fills the inside of the tubing or work string with fluid as well as the annulus. Filling the tubing and annulus should be done at regular intervals (e.g., every 2 to 5 stands). If the crew fails to fill the tubing, the external pressure of the annular workover fluid could collapse the tubing string.

Increase in Well Flow during Circulation A crew can easily observe an increase in well flow by monitoring the fluid stream from the flowline. The stream becomes larger when the well flow increases. On workover rigs equipped with flow indicators, the indicator will show an increase along with an audible alarm. If the flow increase is strong enough, the well may overflow the bell nipple above the BOP and spill onto the ground, the rig floor, or personnel. If any of these signs are apparent, the driller should pick up the string, turn off the pumps, and, if the well continues to flow, immediately shut in the well with the posted procedure (see “Shut-in Procedures” on page 3-4).

Pit Gain Pit gain is an increase in the average level of mud maintained in the tanks. If no surface mud transfers have occurred, then a pit gain is a sign that formation fluids have entered the wellbore. On workover rigs equipped with electronic pit volume totalizer (PVT) systems, an increase in pit volume will be shown on the system’s indicating gauge and an alarm will sound.

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On rigs without PVT systems, pit gain can be visually observed by the crew, who should be monitoring the fluid returns tank. The familiar “nut on a string” tank indicator is an effective indicator as long as it is being monitored. As soon as the crew notices any pit gain, they should notify the driller. The driller should stop circulating, flow-check the well, and be prepared to shut in the well with the posted procedure. The equipment required to monitor fluid returns is covered in Schlumberger IPM standards. (For a list of applicable standards, see “IPM Standards” on page A-14 in the Appendix.)

Shows of Oil or Gas at Surface A sheen of oil on the surface of the fluid in the return tank or the presence of gas bubbles in the returning fluid should be taken as a sign that the well has become underbalanced. The situation should be immediately investigated. This underbalance is an indication that the fluid density in the wellbore needs to be increased. Furthermore, surface hydrocarbons are a fire and explosion hazard, and the crew should take the appropriate safety measures to prevent accidents.

Cut Fluid Weight The presence of formation fluids (oil, gas, or formation saltwater) in the returns can decrease the measured density of the circulating fluid if the formation fluids are lighter than the workover fluid, which is usually the case. The reduction in density, or density cut, indicates that conditions are favorable for more influx to enter the hole. The crew should monitor the density of the circulating fluid and increase it if the density cut appears to be increasing.

Drilling, Milling, or Washing Breaks A drilling break is a sudden increase in the penetration rate when drilling a new formation, milling over packers, or washing out sand plugs or bridges. Breaks may indicate an increase in formation pressure and a corresponding decrease in fluid overbalance. As the overbalance decreases, the bit or mill penetrates more easily and the driller notices that he has to slack off the brake more often to maintain the correct weight. A break is not necessarily a direct indicator of a kick, but rather an 4-10

Well Control for Workover Operations

indicator that the crew should be more alert for direct signs like a flow increase and be prepared to shut in the well.

Increase in Weight Indicator Reading A work string is buoyed somewhat by the weight of the wellbore fluid it displaces. If enough lighter-weight kick fluid enters the wellbore, the weight of the entire volume of wellbore fluid is reduced enough to cause the driller’s weight indicator to show an increase. The driller should watch for a trend of weight increase over time (disregarding, of course, the weight of any tubing or components that have been added to the string).

Well Flow with the Pumps Off Well flow with the pumps turned off is probably the most obvious indicator of a kick. If the well flows when the pumps are not running, the crew should assume a kick has occurred and the well is underbalanced enough to flow. The crew should shut in the well in with the posted procedure (see “Shut-in Procedures” on page 3-4). There are many documented instances of a crew’s failure to shut in a flowing well in time to prevent a kick. Some crews have delayed action while they tried to find other reasons for the flow. In some geographic areas and with some cultures, crews may be hesitant to shut in a well without consulting the WSS, who may not be on the rig floor when the problem arises. Make sure your crew understands that it is imperative not only to shut in the well without delay but also to take responsibility for making this decision on their own.

Lesson 4

4-11

4-12

Well Control for Workover Operations

5 COMPLETION AND WORKOVER FLUIDS Lesson Overview This lesson describes the completion and workover fluids that the WSS must manage when working over wells. There are a number of fluid types used in wells that Schlumberger will work over around the world. This lesson describes the functions, components, and properties of these fluids. This lesson also explains the responsibilities of the WSS in establishing and maintaining the well control functions of completion and workover fluids.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to:

Lesson 5

•

Define the terms completion fluid, packer fluid, and workover fluid.

•

Briefly describe the functions of these fluids.

•

Describe the physical properties and characteristics of workover fluids and how they are measured.

•

Describe the roles and responsibilities of the WSS in managing the well control functions of completion and workover fluids, including controlling and maintaining the density of the fluids, measuring both solids-laden and clear fluids, and preventing any loss of fluid into the formation that would affect primary well control.

5-1

Types of Workover and Completion Fluids A completion fluid is used at the time a well is completed or recompleted. It provides primary well control during the completion process and is designed to minimize damage to the producing interval of the reservoir. A packer fluid is a completion fluid with a specific role. It is placed in the wellbore above a packer in the annular space between the production tubing and the casing. Packer fluids provide hydrostatic pressure to resist the well pressure force from below the packer, helping to hold the packer in place. Packer fluids perform these additional functions: •

Offset the effect of the internal tubing pressure when the well is on production (see “Bullheading” on page 3-28).

•

Provide a noncorrosive environment for the casing and tubing.

•

Provide internal support for the production casing.

Workover fluids are used during operations such as killing the production tubing, displacing the packer fluid, flushing out tubing scale or debris, and conveying fluid loss pills to the perfs. Workover fluids provide hydrostatic pressure for primary well control and help lift and convey cuttings, scale, sand, and contaminants out of the hole. They may also be used as solvents, dissolving crude oil by-products like wax, asphaltenes, and paraffins, which restrict the tubing bore and affect production. Like completion fluids, they are designed to minimize damage to the producing interval unless the interval is to be abandoned.

Functions of Completion and Workover Fluids The functions of completion and workover fluids can be divided into two basic categories: active functions and preventive functions. Active functions involve such capabilities as moving materials through the well, providing or resisting a force, and transferring energy or heat. Preventive functions involve inhibiting or impeding corrosion, bacterial action, formation damage, and so forth.

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Well Control for Workover Operations

Active Functions of Fluids Active functions include the following: •

Primary well control. Workover fluids provide a level of hydrostatic pressure equal to or greater than formation pressure to avoid kicks during the workover operation. When properly controlled and monitored, fluid hydrostatic pressure may be considered as a barrier. (For a review, see “The Barrier Concept” on page 2-40.)

•

Circulation and displacement. Fluids remove unwanted material such as sand, debris, cement, spent acid, cuttings, or milled steel cuttings from the well. Fluids also help to spot or circulate cement, acid, kill pills, gelled pills, or frac sand.

•

Cooling and lubricating. In workovers that involve deepening or sidetracking a well, the fluid cools and lubricates the drill bit. Some workover operations involve milling of downhole equipment like packers and isolation plugs. The fluid allows the mill to function correctly by removing heat and reducing friction while cutting.

•

Operating downhole tools and equipment. The fluid transmits pressure from the pump to the downhole tool or piece of equipment. For example, the pump pressure plus the fluid’s own hydrostatic pressure help operate hydraulically set packers, test tools, and other tools and equipment.

Preventive Functions of Fluids Preventive functions of completion and workover fluids include the following: •

Lesson 5

Minimizing fluid losses to the formation. •

Loss of whole fluid into the formation must be controlled. Kicks will result if the fluid level falls and primary well control is lost. In addition, the formation can be damaged by fluids, and workover costs increase when lost fluid must be replaced.

•

Drilling muds use solids to deposit an impermeable filter cake against the formation. This filter cake minimizes the loss of whole fluid. These same fluids are sometimes used for workovers. The use of these fluids, however, can result in formation damage due to the solids contained in them (see “Displacing to Drilling Muds” on page 5-25). More often, though, clear, solids-free fluids are used to avoid formation permeability damage. These

5-3

clear fluids have no solids to build filter cake with, so they must prevent fluid loss by either their viscosity or by using additives to bridge across the formation. •

Maintaining stability over time and at varying temperatures. This applies particularly to packer fluids. The fluid must be formulated to remain stable for years even at elevated temperatures. If solids separate from the fluid and settle out on top of the packer, the packer may be impossible to retrieve during a workover, necessitating an expensive fishing or milling operation. Furthermore, with the solids separated out, the fluid’s hydrostatic pressure is reduced to that of its base fluid. This reduces the amount of backup it provides to the internal flowing tubing pressure.

•

Preventing formation damage such as oil wetting of reservoir rock, clay swelling, scale precipitation, and solids blockage.

•

Preventing bacterial action in the fluid itself and in the formation. Naturally occurring bacterial colonies are sometimes found in the base fluids used to make up the completion or workover fluid. If the fluid contains a polymer, the bacteria will attack it, degrading the fluid and rendering it useless. Bacterial infestations may occur not only in the fluid but downhole, and these must be controlled as well.

•

Preventing corrosion to tubing, casing, and completion components.

Completion and Workover Fluid Properties The fluids engineer selects various components for the workover or completion fluid so that the fluid will function as needed for a specific well. Each fluid consists of a base fluid plus a weighting agent. Then an additive package is selected to condition the fluid to the individual requirements of the well. The fluids engineer determines whether a fluid meets the job requirements by measuring the following properties:

5-4

•

Density

•

Viscosity

•

Turbidity

•

pH

Well Control for Workover Operations

•

Crystallization temperature

•

Fluid loss rate

Density Density is the measure of the weight of a fluid per unit volume (ppg) or a ratio of the fluids weight to the weight of fresh water, known as its specific gravity (s.g.). A related measure of oil density is API gravity, expressed in degrees. An API gravity of 10 is equivalent to an s.g. of 1, which means the oil has the density of fresh water. Table 5-1 shows the density ranges of various workover fluids. (For a glossary of chemical compound abbreviations, see “Abbreviations for Chemical Compounds” on page A-1 in the Appendix.)

Table 5-1

Densities of Typical Completion/Workover Fluids

Fluid

Density (ppg)

Nitrogen gas Water foam Methyl alcohol Kerosene Diesel Xylene Seawater 2% NaCl 20% NaCl KCl brine ZnBr2/CaBr2/CaCl2 brine 10° API crude 30° API crude 50° API crude Sized CaC03 Iron carbonate Oil-based muds

0.01–2.6 3.5–8.3 6.6 6.7–7.0 6.9–7.1 7.2–7.3 8.45–8.55 8.45 9.58 8.4–9.7 14.0–19.2 8.33 7.30 6.48 8.4–14.0 8.4–18.0 7.0–19.0

The density of completion brines (inorganic salts and water) changes with temperature and must be corrected so that the brine will have the sufficient density downhole to balance the formation pressure at a specific depth. The calculations to determine a brine density thermal correction are shown in Fig. 5-1.

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5-5

PPGRequired = [(BHT - Surface Temp) × Thermal Factor] + PPGFormation + PPGOverbalance PPGRequired = Brine density to be mixed (at surface temperature) PPGFormation = Formation equivalent fluid weight PPGOverbalance = Desired overbalance Bottomhole Temperature (BHT) = Formation temperature (degrees F) Surface Temp = Surface temperature (degrees F) Thermal Factor = Value from table below (based on brine density range) Brine Density

Thermal Factor

8.4 to 9.0 9.1 to 11.0 11.1 to 14.5 14.6 to 17.0 17.1 to 19.2

0.0017 0.0025 0.0033 0.0040 0.0048

Example: Given: Surface Temp = 90°F, BHT = 205°F, Formation = 13.2 ppg Find: Required density at surface (with 0.2 ppg safety margin) Solution: Thermal Factor for 13.2 = 0.0033 PPGRequired = (205-90) × 0.0033) + 13.2 + 0.2 = 0.379 + 13.2 + 0.2 = 13.78 = 13.8 ppg Figure 5-1

Brine density thermal correction

The density of brines (and oils) is measured with a hydrometer (Fig. 5-2). A hydrometer measures specific gravity (not ppg). An attached thermometer and a temperature correction chart on the back of the hydrometer make it possible to 5-6

Well Control for Workover Operations

correct the measured density to the standard 60°F. Densities in a workover program should always be based on this reference temperature. Glass hydrometer for determining specific gravity. It has a weighted tip and a graduated, directreading tube. Hydrometers are available in a variety of sizes and ranges.

Figure 5-2

Hydrometer

Solids-laden drilling fluids (modified for completion and workover needs) can be weighed in ppg with the familiar rig mud balance or pressurized mud scale.

Viscosity Viscosity is the resistance of a fluid to flow. Different fluids have different viscosities. For example, tar has a higher viscosity than water; 40W motor oil has a higher viscosity than 10W. Completion and workover fluids normally have low viscosities. When required, viscosity is increased with various additives. Increasing viscosity enhances the ability of the fluid to carry or suspend solid particles. It also helps prevent the fluid from flowing into the perfs. The workover crew takes two measurements of the fluid’s viscosity. The crew measures funnel viscosity by pouring 1,500 ml of fluid into a Marsh funnel and recording the time (in seconds) that the fluid takes to flow out of the funnel. The fluids engineer uses a device called a rheometer to measure the plastic viscosity in

Lesson 5

5-7

centipoises (cp). Both measurements are important. Funnel viscosity can be used by the personnel mixing the fluid to determine when the proper value has been reached and to monitor viscosity changes during the workover procedure. A more detailed analysis done by the fluids engineer using the rheometer determines the cause of the change in viscosity or monitors the results of fluid conditioning or chemical treatments.

Turbidity Turbidity is related to the cleanliness of the fluid. This property is important when workovers are done in damage-sensitive formations that require clear, solids-free fluids. If a fluid contains undesirable particles of silt, clay, algae, and the like, it scatters light and appears turbid or cloudy. If a fluid is particle free, it appears clear, the opposite of turbid. Turbidity is measured by a turbidity meter, and the measurement is commonly reported in nephelometric turbidity units (NTUs).

pH The pH of a fluid is a measure of its acidity or alkalinity. The pH scale ranges from 1 to 14, with 1 being the most acidic. The fluids engineer measures pH with a pH meter or litmus paper. He monitors the pH and controls it to limit corrosion downhole, inhibit scale formation, limit formation clay swelling, and ensure that the components of a completion and workover fluid function together properly.

Crystallization Temperature If the temperature of the fluid falls below a certain point, brine completion or workover fluids containing dissolved salts will crystallize (freeze) or lose density as their salts fall out of solution. When crystallization occurs, crystals give the brine the appearance of slush. The viscosity of the fluid may increase to the point where the crystals plug the lines and the fluid becomes unpumpable. The crew needs to know at what point this crystallization takes place. The fluids engineer or project engineer performs a test using the LCTD (Last Crystal to Dissolve) method. In this test, the brine is stirred constantly as it is cooled below the point where the first crystals appear. Then the fluid is warmed until the last crystal dissolves, which indicates its crystallization temperature, or LCTD. At the

5-8

Well Control for Workover Operations

crystallization temperature, the least soluble salt becomes insoluble and precipitates out of the liquid. Cooling the brine below this temperature results in even more precipitation of solids. This data is published for all the common brines used and can be found in the M-I Completion Fluids Handbook. The fluids engineer specifies a brine formula that takes into account the fluid’s crystallization tendencies and the temperatures likely to be encountered in the workover operation.

Fluid Loss Rate As stated earlier, drilling fluids use solids to deposit a filter cake against the formation. The fluid engineer can check the effectiveness of the filter cake with a standardized API test called API water loss, which measures the loss rate of the filtrate (liquid portion) of the fluid through the permeable filter cake left by the solids in the fluid.

Components of Completion and Workover Fluids Each fluid begins with a base fluid and a weighting agent. Then an additive package is selected to condition the fluid to fit the specific characteristics of the well. The workover crew may use an oil-based fluid, a water-based fluid, a clear brine, or another base fluid. Normally the base fluid chosen is the least expensive one that satisfies two basic requirements: •

It must be capable of controlling the well.

•

It must protect the formation from permanent permeability damage.

Base Fluid Fluids have two basic components: a liquid or gas (the base fluid) and solids to condition the base fluid to meet the requirements of the well. Workover crews may use oil, water, gas, or clear brine as the base fluid. Water is the easiest to use and is less expensive than oil-based fluids or gas, but it is not always suitable for a particular formation.

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5-9

Water The water in a water-based fluid may come from a variety of sources including produced water (lease saltwater), fresh water, potable water, drinking-quality water, treated brackish water from marshes, or treated seawater.

Oil Crude oil, diesel, mineral oil, or synthetic vegetable-based oil may be used as a base.

Gas For gas-based systems, nitrogen gas is combined with water and a chemical called a surfactant to create stable foam. Foams are used in workovers on wells that have very low formation pressures and therefore will not support the weight of a column of liquid. Nitrogen densities range from 1 to 5 ppg.

Clear Brine Clear brine is a fluid made up mainly of chemical salts, such as sodium, chloride, calcium, or potassium chloride. This base contains little or no clay or other solid material and is virtually clear. It is used frequently because it minimizes formation damage.

Weighting Material The weighting material in the fluid can be barite (barium sulfate), limestone (calcium carbonate), or inorganic salts such as zinc bromide, calcium chloride, sodium chloride, or potassium chloride.

Additives Additives are used to condition the fluid to meet the well requirements. The most common fluid additives and their basic uses are listed in Table 5-2.

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Well Control for Workover Operations

Table 5-2

Common Additives and Their Uses

Additive

Use

Viscosifiers Surfactants Bridging agents pH control Inhibitors Bactericides

Fluid loss control, gas migration control, suspending agent Aids in recovering fluid used to load hole, emulsifier Fluid loss control Clay damage control, corrosion control, H2S inhibition Scale and corrosion control Controls bacteria counts

Water-Based Fluids Conventional water-based drilling fluids can be used for workovers when a zone is to be abandoned and the inherent solids damage to the formation is not an issue. They may also be used in wells perforated with an intentional underbalance. These wells are immediately flowed through the perfs and put on production, thus reducing the possibility of solids damage to the formation. The physics of familiar water-based drilling muds are not within the scope of this manual. For information on their components and properties, consult the M-I Drilling Fluids Manual. Clay-free fluids use sized particles of organic salts or calcium carbonate to provide density and to bridge across pore spaces, preventing fluid loss to the formation. The particles in these muds, unlike clay minerals, can be dissolved in an appropriate solvent (water or acid), eliminating permanent formation damage.

Oil-Based Fluids An oil-in-water emulsion is a fluid of about 40% oil in a salt brine. It is used while gun perforating. Solids-laden oil-based muds contain solids for weighting material (called organophyllic clays), but have no free water and are thus selected to protect watersensitive clays. True oil-based mud contains only about 5% water. The base oil (usually diesel) is dispersed as small droplets in the water, with emulsifying agents added to keep the water and oil from separating. Invert emulsion mud contains 10– 30% water, which is dispersed as small droplets in the oil. For completion and

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5-11

workover use, the true oil-based muds are generally preferred as they are less damaging to the formation.

Clear Brine Fluids Brine is water saturated with a large amount of salt. Brine fluids are used worldwide. They are readily available, safe for most formations, nonflammable, low-solids or solids-free, inexpensive in the lower density ranges (up to about 11.5 ppg), and, in these lower densities, convenient to mix on the rig. In the higher density ranges, they can be corrosive to completion components, very expensive, and even toxic to personnel and the environment. Many of the brine systems are run solids-free, which involves extensive filtration, sampling, and testing (see “Brine Filtration Units” on page A-13 in the Appendix). Densities for the various commercially available brines are shown in Table 5-3.

Table 5-3

Densities of Some Commercially Available Brines

Fluid

Density Range (ppg)

Potassium chloride (KCl) Sodium chloride (NaCl) Sodium/calcium chloride (NaCl/CaCl) Calcium chloride (CaCl2) Zinc/calcium chloride (ZnCl2 Potassium bromide/chloride (KBr/KCl) Sodium bromide/chloride (NaBr/NaCl) Calcium choride/bromide (CaCl2/CaBr2) Zinc bromide/calcium bromide/calcium chloride (ZnBr2/CaBr2/CaCl2)

8.4–9.7 8.4–9.7 10.0–11.0 11.0–11.7 12.0–16.0 9.8–10.9 10.0–12.4 11.7–15.1 14.0–19.2

Brine fluids can be prepared on the rig or obtained premixed from fluid manufacturers. The crew must treat the heavy brines to reduce their corrosive tendencies and take care not to precipitate out the salt. The risks to personnel and the environment are significant. Brines are made from a water base (either drinking water, treated potable water, or treated lease water), one or more salts selected for the required density, and, if required, viscosifiers, pH control agents, and corrosion control agents.

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Well Control for Workover Operations

One problem that workover crews must keep in mind when using a clear brine is brine crystallization (see “Crystallization Temperature” on page 5-8). If the salt crystallizes, it can plug lines and valves. If it settles in the fluid tanks, the density of the fluid may change and, when pumped back into the hole, may not be high enough to maintain primary well control. Fortunately, the process is reversible. Reheating the brine above its crystallization temperature dissolves the solids with no permanent change in the brine properties.

Commonly Used Brines Some of the most commonly used brines include: •

Sodium chloride

•

Potassium chloride

•

Calcium chloride

Sodium Chloride Statistically, sodium chloride (NaCl) is the most commonly used brine. It can be mixed in densities from 8.4 to 9.8 ppg. Many brine charts show the upper limit of NaCl brine as 10.0 ppg, but 10.0 ppg is difficult to achieve in the field. That number is based on laboratory conditions—using distilled water and chemically pure salt and stirring with a high-speed blender. The crystallization temperature range is 31°F for 8.4 ppg down to -5°F for 9.8 ppg. Table 5-4 indicates the quantities for mixing NaCl brine to different densities and also shows their corresponding crystallization points.

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5-13

Table 5-4

Composition and Properties of Sodium Chloride Brine

Brine Density

To Make 1 bbl (42 gal)

Cryst. Point

(60 degrees F)

Water (bbl)

100% NaCl (lbs)

(degrees F)

8.4 8.5 8.6 8.7 8.8 8.9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8

0.998 0.993 0.986 0.981 0.976 0.969 0.962 0.955 0.948 0.940 0.933 0.926 0.919 0.910 0.902

4 9 16 22 28 35 41 47 54 61 68 74 81 88 95

+31 +29 +27 +26 +24 +22 +19 +17 +14 +11 +9 +6 +3 -1 -5

Potassium Chloride Potassium chloride (KCl) can be mixed in densities from 8.4 to 9.7 ppg. The crystallization temperature range is 31°F for 8.4 ppg to 60°F for 9.7 ppg. Table 5-5 gives quantities for mixing KCl brine to different densities and the corresponding crystallization points. A 2% KCl solution, which requires NaCl, is so commonly used (for clay inhibition) that a mixing table is included for reference (see Table 5-6).

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Well Control for Workover Operations

Table 5-5

Composition and Properties of Potassium Chloride Brine

Brine Density

To Make 1 bbl (42 gal)

Cryst. Point

(60 degrees F)

Water (bbl)

100% KCl (lbs)

(degrees F)

8.4 8.5 8.6 8.7 8.8 8.9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 9.7

0.995 0.986 0.976 0.969 0.960 0.950 0.943 0.933 0.924 0.917 0.907 0.898 0.890 0.881

4.0 11.6 18.9 26.1 33.4 40.7 47.9 55.2 62.4 69.7 76.9 84.2 91.5 98.7

+31 +29 +28 +26 +25 +23 +22 +20 +18 +16 +14 +18 +40 +60

Table 5-6

Mixing 2% Potassium Chloride Solution

Brine Density (60 degrees F)

NaCl (lbs per bbl water)

KCl (lbs per bbl water)

8.5 8.8 9.0 9.2 9.4 9.6 9.7

0 18.0 31.0 45.0 62.0 76.0 97.0

7.15 7.40 7.60 7.76 7.90 8.10 9.25

Calcium Chloride Calcium chloride (CaCl2) can be mixed in densities from 8.4 to 11.6 ppg, so it provides a large density range. The crystallization temperature range is 31°F for 8.4 ppg to 44°F for 11.6 ppg. Dry calcium chloride is available in two grades: 77% and 94%. The 94% grade is preferred since it contains fewer unidentified solids.

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5-15

For economic reasons, solutions of NaCl/CaCl2 are sometimes used instead of CaCl2 only. Mixing CaCl2 produces an exothermic (heat-generating) reaction, so the WSS should ensure that personnel take precautions to avoid burns. Table 5-7 gives quantities for mixing CaCl2 brine to different densities and the corresponding crystallization points.

Table 5-7

Composition and Properties of Calcium Chloride Brine

Brine Density

To Make 1 bbl (42 gal)

Cryst. Point

(60 degrees F)

Water (bbl)

100% CaCl2 (lbs) (degrees F)

8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.6 10.8 11.0 11.2 11.4 11.6

0.998 0.992 0.986 0.980 0.970 0.959 0.949 0.940 0.929 0.919 0.909 0.899 0.889 0.879 0.866 0.854 0.842

3.8 14.3 24.8 35.3 47.2 59.1 71.1 83.0 94.9 107.0 119.0 131.0 143.0 155.0 167.0 180.0 193.0

+31 +28 +25 +21 +17 +12 +6 0 -8 -18 -29 -43 -59 -22 0 +27 +44

Supervisor’s Roles in Maintaining Properties Since some workovers are performed in remote areas without the direct assistance of a fluids engineer, the WSS must have a basic knowledge of methods for maintaining fluid properties as well as an understanding of rheology, fluid cleanliness and filtration, and QHSE issues. This section focuses on density control and fluid loss control, which are of primary importance in controlling the well during workovers.

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Well Control for Workover Operations

Density Control The WSS will occasionally need to build completion or workover fluids. Many workovers require a very simple fluid, such as NaCl brine, 2% KCl, or a conventional drilling mud, and the workover program may call for the fluid to be mixed on the rig. At other times, the WSS will have to change the density of commercially prepared brines. For example, if an order of 10.2 ppg brine proves to be only 9.7 ppg when delivered to the rig and weighed, the crew will have to increase its density. The equations in Fig. 5-3 and Fig. 5-5 can be used to calculate the amount of salt required to increase fluid density.

Solids-Laden Fluids The equation in Fig. 5-3 is used to determine the amount of weight material required to change the density of a solids-based fluid in which the solid does not dissolve in the base fluid (e.g., barite, calcium carbonate). Note that there are separate equations for brines.

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5-17

Weight of Material Required (lbs per bbl base fluid) = ppb solid × fw2 - fw1 ÷ (ppg solid - fw2) ppb solid = pounds per barrel of weight material (barite = 1,470) ppg solid = pounds per gallon (ppg) of weight material (barite = 35) fw2 = desired fluid weight, ppg fw1 = initial fluid weight, ppg Example: Given: 500 bbl weighted barite-based fluid with a density of 9.6 ppg Find: Pounds of barite required to increase density to 10.2 ppg Solution: Pounds per barrel = 1,470 × (10.2 - 9.6) ÷ (35 - 10.2) = 1,470 × 0.6 ÷ (24.8) = 35.56 ppb Total pounds required = 35.56 × 500 = 17,178 lbs

Figure 5-3

Increasing density in solids-laden fluids

To decrease the density of a solids-laden fluid by adding water, use the equation in Fig. 5-4.

5-18

Well Control for Workover Operations

Liquid Volume Required to Reduce Density of Solids-Laden Fluids Initial Fluid Volume (bbls) × ( W 1 – W 2 ) Liquid Required (bbls) = ----------------------------------------------------( W2 – Dw ) where: W1 = Original fluid density (ppg) W2 = Desired reduced fluid density (ppg) Dw = Density of liquid used to dilute (ppg) Example: Given: 100 bbls of 14.0 ppg oil-based fluid; diesel with density 7.0 ppg Find: Barrels of diesel to dilute fluid to 12.0 ppg Solution: 200 100 × ( 14.0 – 12.0 ) Liquid Required = ------------------------- = ---- = 40 bbls diesel 5.0 ( 12.0 – 7.0 ) Figure 5-4

Decreasing density of solids-laden fluids

Single-Salt Brines Building a single-salt brine to a specified density is a simple procedure that involves using commonly available brine tables (see Table 5-4 through Table 5-7). The tables show the required salt and water volumes to build one barrel of the required density. Multiply those numbers by the desired total volume to determine the total salt and total water required. The density of an existing brine can be increased by adding salt, using the brine tables along with the equation in Fig. 5-5. Brine density is decreased by dilution—i.e., by adding fluid (generally fresh water). Fig. 5-6 provides the required calculations.

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5-19

Pounds of Salt Required (per bbl existing brine) = Wi × Sf ÷ Wf - Si Final Brine Volume = Initial Volume × Wi ÷ Wf Wi = water per bbl (from table) at initial density Wf = water per bbl (from table) at desired density Si = salt per bbl (from table) at initial density Sf = salt per bbl (from table) at desired density Example: Given: 200 bbl of 10.4 ppg CaCl2 brine Find: Pounds CaCl2 to increase density to 11.0 ppg and final volume Solution: From Table 5-7: Wi = 0.909, Wf = 0.879, Si = 119.0, Sf = 155.0 Added salt per bbl = 0.909 × 155.0 ÷ 0.879 - 119.0 = 41.29 lbs/bbl Total salt required = 41.29 × 200 = 8,258 lbs Final volume = 200 × 0.909 ÷ 0.879 = 206.82 bbl Figure 5-5

5-20

Increasing density in single-salt brines

Well Control for Workover Operations

Barrels of Fluid Required to Decrease Density (per bbl existing brine) = (Di - Df) ÷ (Df - Da) Di = initial brine density, ppg Df = desired brine density, ppg Da = density of fluid added to dilute, ppg (fresh water = 8.33 ppg) Example: Given: 150 barrels of 9.9 ppg NaCl brine Find: Barrels of water to dilute to 9.4 ppg Solution: Di = 9.9 ppg, Df = 9.4 ppg, Da = 8.33 ppg Water required per barrel = (9.9 - 9.4) ÷ (9.4 - 8.33) = 0.467 bbl per bbl Total water required = 0.467 × 150 = 70.05 bbl Figure 5-6

Decreasing density by dilution

Decreasing brine density will change the crystallization temperature (as shown in Table 5-4 through Table 5-7), so the brine may freeze at a higher temperature. Always check the appropriate brine table for the fluid you are using. Look up the crystallization temperature at the final density. If the ambient temperature in the mixing and storage area is likely to be lower than that, take precautions. If the mixing and storage area is enclosed, use space heaters to raise and maintain the brine temperature above the crystallization temperature before changing the density.

Multiple-Salt Brines Two- and three-salt brines are needed to achieve the higher densities required to control higher formation pressures. Some of these brines can be mixed to 19.2 ppg density (see Table 5-3). However, changing these brine weights in the field must be done carefully to avoid salt precipitation. Water additions and exact salt proportions are required when increasing density, or the least soluble salt(s) can precipitate out. Equations for calculating salt and water additions are more complex than for single

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5-21

salts. When working with these heavyweight fluids in the field, experienced fluid personnel are required on location to maintain correct fluid properties. For an example of a two-salt brine density calculation, see “Increasing Density in Multiple-Salt Brines” on page A-8 in the Appendix.

Thermal and Crystallization Effects on Density Commercially premixed brines are used in many workovers where formation pressure requires greater than about 11.5 ppg fluid. Generally, the completion engineer who developed the workover procedure will specify the brine properties. The brine plant will need to know the minimum and maximum expected temperatures so that the brines are optimally mixed to yield required densities under downhole temperature conditions and still prevent crystallization in the coldest expected ambient conditions for the geographic location and the season. For example, Wyoming, USA, might have a range of -20°F air temperature to 160°F bottomhole temperature in the winter. Brines can be ordered in “summer” or “winter” blends, which allows for seasonal temperature ranges. When weighing a brine on the rig, use a brine hydrometer instead of a mud balance, which can produce an error of up to 0.5 ppg. The hydrometer’s temperature correction capability was discussed earlier (see “Density” on page 5-5). The equation for correcting temperature with a hydrometer is shown in Fig. 5-7.

5-22

Well Control for Workover Operations

Corrected Brine Density (ppg) = Specific Gravity × 8.33 × Temp. Conversion Example: Given: Air temperature = 92°F, s.g. = 1.2; temperature conversion table value = 1.110. Find: Brine weight in ppg, corrected for standard temperature Solution: Corrected Brine Density = 1.2 × 8.33 × 1.110 = 11.095 = 11.1 ppg Figure 5-7

Temperature correction with a hydrometer

Remember that the density of the crude oil in the hole is also temperature sensitive. If a mud balance is used to weigh the oil, the actual downhole density will be less and must be corrected with the appropriate equations (see “Crude Oil Hydrostatic Pressure” on page 2-11). If a hydrometer is used to measure the density of the oil, a temperature correction for the oil can also be calculated with the equation in Fig. 5-7.

Unintentional Brine Dilution Brines can lose density when they become inadvertently diluted with water, as when rainwater or rig washdown water enters the brine tank. Brines (especially the heavy multiple-salt brines) can also become diluted by absorbing water directly out of the air. For these reasons, brines (like oil-based muds) should be stored in covered tanks on the rig.

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5-23

Control of Fluid Loss There are two ways to prevent the loss of fluid downhole: •

Treat the entire fluid system with fluid loss agents.

•

Treat a portion of the fluid and pump it into place adjacent to the zone exhibiting the loss. This method is called a pumping a kill pill.

Treating with Fluid Loss Agents In low-permeability zones, you can add polymers such as HEC to increase the fluid’s viscosity. The polymer slows the flow of fluid into and through the pore spaces of the formation. In high-permeability zones—zones that exhibit a high loss rate, as in vugular formations or naturally fractured zones—you can add a variety of bridging agents to the fluid to mechanically block the leak path. Unlike traditional lost circulation materials (LCMs) used in drilling, these agents are all degradable, so they do not cause permanent permeability damage. They are intentionally dissolved when no longer needed with either water, formation oil, or acid.

Mixing and Spotting a Kill Pill Good results have been obtained in the field with a simple pill of gel polymer used with a saltwater (NaCl, KCl, etc.) workover fluid.

5-24

1

Mix 2 to 3 pounds of a polymer (such as HEC) per barrel of workover fluid for a total pill volume that covers the perforated interval plus about 50% (20 to 40 barrels is normally sufficient).

2

Circulate sufficient pump strokes to spot the pill across the perfs, leaving a reserve of pill in the tubing.

3

Monitor the hole level, allowing 1 to 2 hours for the pill to stop losses or slow them to an acceptable level. If the hole level drops, fill the hole from the tubing side to displace more pill across the perfs.

Well Control for Workover Operations

Displacing to Drilling Muds Drilling muds have been used to control a kick when kill attempts with clear fluids have failed. Some companies have taken as long as two weeks to kill a highproductivity gas well with an overbalanced clear, solids-free fluid, supplemented with gelled kill pills. The wells would repeatedly come back in after they appeared to be static for hours. (Water and gas change places in the near-wellbore vicinity even when a static overbalance exists.) Eventually the fluid systems were converted to mud and the wells successfully killed. Remaining fluid losses were minimal, so the workover could proceed with the well standing full of fluid. Unfortunately, formation damage from the mud solids was evident when the wells were placed back on production. In a borderline situation like the one described above, the decision to continue with clean fluids may hinge on the WSS’s ability to constantly supervise the operation as well as the experience and skills of the contractor crew and their supervisors. Constant vigilance is required—the crews must constantly monitor and fill the hole and run or pull tubing at the correct speed to avoid swab and surge pressures. A well at near-balanced conditions “drinks” clear fluid and must be observed constantly. A slight swab or surge will cause the well to flow. A few bubbles migrating to the surface will expand and unload enough fluid to cause the well to flow. On daylight rigs a new well kill may be required each morning when the well is reopened. If the crews are inexperienced or the toolpusher has not demonstrated competency, the WSS may consider the use of drilling mud. Remember that the client normally hires the crew to do workovers with a goal in mind of restored or improved production. Make every effort to ensure that the fluid is selected and maintained in a way that does not detract from that goal.

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5-25

5-26

Well Control for Workover Operations

6 SURFACE AND SUBSURFACE EQUIPMENT Lesson Overview This lesson describes the equipment that is typically involved in workover operations. Included in this group are downhole completion equipment, the Christmas tree, the wellhead, wireline, and conventional BOP equipment.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to:

Lesson 6

•

Identify and describe downhole equipment configurations in the common completion types, including flowing wells and those requiring artificial lift.

•

Describe the basic types and functions of packers, landing nipples, side-pocket mandrels, sliding sleeves, blast joints, flow couplings, and downhole safety valves.

•

Identify and describe the “A,” “B,” and “C” sections of a wellhead.

•

Describe the function of the various Christmas tree components.

•

Explain wireline surface equipment used for pressure control.

•

Describe the function and purpose of the surface safety system.

6-1

•

Describe the types, functions, and uses of conventional BOP equipment, including annular preventers, ram preventers, safety valves, chokes, BOP control systems, accumulators, and back-pressure valves.

•

Determine accumulator volume requirements for a workover rig in accord with Schlumberger policy.

•

Understand and describe testing requirements for conventional, slick wireline, and braided wireline BOPE.

Typical Completions This section shows typical completions used in various geographic areas (see Fig. 6-1 through Fig. 6-8). The typical completion components for each type are illustrated along with key points relating to well control, safety, and other issues. A description of the individual components follows this section.

Key Points

• • •

Figure 6-1

6-2

Circulating well-kill capability No control of annular fluid level Exposure to corrosion

Open-ended completion

Well Control for Workover Operations

Key Points

• •

• •

Figure 6-2

Bullheading well-kill capability Circulating well-kill capability after unsetting retrievable packer. In case of permanent packer, seal assembly must be pulled from packer. Treated packer fluid protects casing string from corrosion Packer fluid provides fluid backup to tubing internal burst pressure

Basic single-zone packer completion

Key Points

Same as with basic packer completion, plus: • Isolation plug capability above and below packer • Circulating capability through sliding sleeve without unsetting packer • String accepts production safety valve (SCSSSV)

Figure 6-3

Lesson 6

Packer completion with nipples, sliding sleeve, and SCSSSV

6-3

Key Points

•

• •

Figure 6-4

Allows independent production through two tubing strings and from multiple zones Circulating capability to annuli via sliding sleeves Complex configuration may complicate well control operations because of numerous possibilities for leak paths and cross-communication between zones of differing reservoir pressures

Multiple-zone, multiple-string completion

Key Points

•

•

Figure 6-5

6-4

Using special service tools and procedures, gravel is placed in and around perfs to control sand production Gravel pack equipment easily damaged when running, requiring special care

Sand-control completion

Well Control for Workover Operations

Key Points

•

•

•

Reciprocating pump assembly connected to downhole pump by rod string. On upstroke, oil is sucked into traveling valve. On down stroke, standing valve closes so oil is pushed up through traveling valve and into hollow tubing string and toward surface. Rod pumping accounts for majority of onshore artificial lift completions. Swabbing likely when pulling rod string during workover. Hazardous if H2S present.

Figure 6-6

Lesson 6

Artificial-lift completion—rod-pumped

6-5

Key Points

• •

•

• •

•

Figure 6-7

6-6

Gas lift used in 90% of offshore wells that are artificially lifted. Oil is lifted by injecting a stream of gas into it, which expands as it rises, increasing the fluid velocity while reducing its effective density. Gas injection volume, pressure, and number of injection points are a function of tubing diameter, tubing volume, formation pressure, liquid density, and depth. Frequent workovers required to service gas-lift valves. Gas hydrates can form in completion string and surface equipment, complicating well control operations. Casing is exposed to high gasinjection pressures.

Artificial-lift completion—gas-lift

Well Control for Workover Operations

Figure 6-8

Artificial-lift completion—electric submersible pump (ESP)

Completion String Components This section describes the functions of the principal completion string components. (Further information may be found in the Schlumberger document “Oil and Gas Well Completions, Rev E, December 1996.”) In addition to the tubing, these components include the following:

Lesson 6

•

Production packers

•

Completion accessories

•

Subsurface safety valves

6-7

•

Tubing Hangers

•

Bridge Plugs

Production Packers Although the makes, models, and types of completion packers vary significantly, they have one thing in common: they enable efficient flow from the producing formation to the tubing string(s) without restricting production capability. They have the following basic functions: •

Annulus isolation Packers seal the annulus between the tubing string(s) and the casing or liner. This creates improved flow up the tubing for production and also allows the annulus to be used as a separate conduit when gas lift is required (see Fig. 6-7).

•

Downhole anchor Many packers provide a downhole anchor point for the tubing string.

•

Casing string protection The sealed annulus created by the packer protects the casing string or liner from formation pressure and from corrosive conditions.

•

Zone isolation Packers isolate different producing zones in the same wellbore. Isolation of zones may be required to meet regulatory requirements in some areas. Isolating zones also serves to prevent crossflow of reservoir fluid between high- and lowpressure zones.

There are several ways of categorizing the multitude of packer types used in the industry. Two major categories are retrievable packers and permanent packers.

Retrievable Packers Retrievable packers (Fig. 6-9) can be disengaged and brought to the surface with the completion string. This type of packer is generally preferred when the completion life is relatively short, the downhole environment is not hostile, multiple-zone completions are planned, or frequent workovers are required. They are further categorized by the way they are set.

6-8

Well Control for Workover Operations

Lesson 6

•

Hydraulically set packers (Fig. 6-9) are set without mechanical manipulation of the tubing string. When the packer has been run to depth, hydraulic pressure is applied to the fluid in the tubing string against a temporary plug or drop ball that isolates the formation from the applied hydraulic pressure. At a specific hydraulic pressure, shear pins in the hydraulic setting mechanism break, allowing the packer slips to be forced out and the sealing elements to be compressed, sealing the packer against the casing so that oil or gas cannot flow into the annulus. After the packer is set, energy is stored in a ratchet mechanism that keeps the slips and seals engaged, thus securing the packer without the need for continual tubing weight or tension, as in mechanically set packers.

•

Mechanically set packers (Fig. 6-9) are the most commonly used type in the industry. Also called hookwall packers, these are set and released by movement of the tubing string—either rotation, weight, or tension at the packer. The basic design concept is that a certain amount of load is applied to the packer through the tubing string at installation. That load is intentionally trapped in the completion so that subsequent wellbore temperature and pressure variations do not cause the tubing or packer forces to exceed their operating limits.

6-9

Figure 6-9

Retrievable packers

Permanent Packers Permanent packers (Fig. 6-10) are designed to be installed and left in the hole. If removal is necessary, they have to be milled out or drilled out. These packers are generally used when completion life expectancy is long or when wellbore conditions are hostile (e.g., high pressure, high temperature, high packer loading, or high H2S content). They are used when it is likely that future workovers will only require retrieving the tubing. One commonly used type of permanent packer is called a seal bore packer. It can be configured to allow for the shortening and lengthening of the tubing string that results from thermal effects in the well, as shown in Fig. 6-10.

6-10

Well Control for Workover Operations

Figure 6-10 Permanent packers

During workovers, trapped pressure below these packers can have serious well control consequences (see “Trapped Pressure below Packers” on page 7-23).

Tubing Hangers The tubing hanger anchors the production tubing to the Christmas tree. It resides in the tubing bowl in the “B” section of the wellhead (Fig. 6-16) and is held in place, in part, by the weight of the tubing and hold-down pins, which are part of the tubing bowl. Once the hanger is landed, the hold-down pins are run in and tightened. Elastomeric seals seal off the top of the annulus (see Fig. 6-11). Most tubing hangers contain internal threads or a machined profile for the installation of a backpressure valve (Fig. 6-42). Lesson 6

6-11

The tubing hanger can also be a point of attachment for a hydraulic control line that operates surface-controlled subsurface safety valves (Fig. 6-15).

Figure 6-11 Typical tubing hangers

6-12

Well Control for Workover Operations

Bridge Plugs Bridge plugs are special plugging devices that can be set as temporary isolation tools to be retrieved at a later date, or they can be installed as permanent plugging and isolation tools. They are used for zonal isolation during stimulation or cement jobs as well as for temporary or permanent well abandonment. They can be run on wireline or tubing and are designed to be set in either casing or tubing. Expandable models are also available. They are run through the tubing string and then set in casing. Fig. 6-12 shows examples of common wireline and mechanically set bridge plugs. The particular bridge plugs shown are permanent plugs and are also drillable.

Figure 6-12 Bridge plugs

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6-13

Completion Accessories Besides the production tubing and packer, the completion string may include a variety of accessories. These accessories serve as landing points for retrievable tools, well shut-in devices, annular access points, and other equipment and are described in the following sections.

Landing Nipples The production string must serve as a receptacle for many kinds of retrievable internal tools, such as downhole chokes, regulators, plugs, and instrument packages. These tools are generally categorized as flow-control devices. In order to accommodate these tools, the string is configured with various devices called landing nipples. These nipples provide: •

a space to locate the tool

•

a means to pressure-seal around the tool

•

a way to lock the tool into place

Landing nipples have an internal sealing surface and a locking recess that mates with a lock that is run with the tool itself. Although there are design variations between manufacturers, landing nipples can be placed in two general categories: “no-go” nipples and selective nipples.

6-14

•

“No-go” nipples (Fig. 6-13) have a restricted ID on which downhole tools locate. A locating shoulder on the tool assembly is larger than the ID of the shoulder inside the nipple, so the tool cannot go past that point, hence the name “no-go.” There is a sealing section and a lock recess on the nipple as well. A nogo nipple may be run alone as a single nipple in a string or as the bottom nipple below a series of selective landing nipples. An entire series of no-go nipples may be run in a completion string with decreasing IDs from top to bottom.

•

Selective nipples (Fig. 6-13) do not use a locating shoulder to serve as a landing place for flow-control devices. The locks run with the flow-control tools have retractable dogs that spring outward and engage a lock recess in the nipple. Without the interference of a locating shoulder, the tools can be run through a number of nipples and then set in the desired nipple by the wireline operator. Fig. 6-14 shows a tool assembly locked into place in a selective landing nipple.

Well Control for Workover Operations

Figure 6-13 Typical landing nipples

Lesson 6

6-15

Figure 6-14 Flow-control device locked into a selective landing nipple

It is imperative that the WSS document the actual depth and description of nipples that have been run with a completion. The well will eventually be worked over again, and the documentation will be critical for wireline operations at that time.

Side-Pocket Mandrels These landing devices are offset from the tubing centerline in order to house tools while still providing an unrestricted flow path up the tubing. Tools such as gas-lift valves, chemical injection valves, and circulating valves can be landed in sidepocket mandrels (see Fig. 6-7).

6-16

Well Control for Workover Operations

Sliding Sleeves Siding sleeves provide communication between the tubing and the annulus and are used to circulate during well kills or to selectively produce a zone (see Fig. 6-3). Sliding sleeves can be opened or closed with specialized wireline shifting tools.

Flow Couplings Flow couplings are sections of heavy-walled tubing installed above and below completion equipment, like nipples, that cause turbulent fluid flow. The heavy wall resists the erosive effects of the flow.

Blast Joints Blast joints are heavy-walled tubing joints that are hardened, heat-treated, and often covered with resilient material. Blast joints are installed in the completion string adjacent to producing zones to withstand the scouring action of fluid flowing from the perforations.

Subsurface Safety Valves These valves shut off well flow through the tubing bore. Tubing-retrievable safety valves are integral to the tubing string and can be retrieved only by removing the entire string. Wireline-retrievable safety valves are located in landing nipples and are installed and removed with wireline tools. These valves are further classified by the way they are controlled:

Surface-Controlled Subsurface Safety Valves (SCSSSV) These safety valves have a connection for a hydraulic control line that runs back to the surface (see Fig. 6-15). A control panel on the surface is used to close the valve, either by manual intervention or with an automatic system that actuates in an emergency such as fire or uncontrolled well flow downstream of the valve. The valves are also designed to self-close if hydraulic control pressure is lost. They are mandatory in many producing areas, particularly offshore. SCSSSVs are set at the shallowest possible depth so that if the hydraulic control line is damaged, the hydrostatic pressure of the annular fluid will not open the valve. They are also set at shallow depths to facilitate retrieval and repair.

Lesson 6

6-17

Figure 6-15 Surface-controlled subsurface safety valve (SCSSSV)

Subsurface-Controlled Subsurface Safety Valves (SSCSSV) This type of safety valve is controlled by well conditions. When downhole pressure or flow velocity reaches a preset value of differential pressure, the valve will close automatically. The valve is actuated by the pressure differential across the valve that is created by increased fluid velocity, which occurs when the integrity of the production string above the safety valve is broken. These valves are also called storm chokes.

6-18

Well Control for Workover Operations

Wellhead and Christmas Tree A wellhead is customarily divided into three sections for descriptive purposes: “A,” “B,” and “C” (see Fig. 6-16).

Figure 6-16 Typical wellhead and Christmas tree

The “A” section consists of the lower wellhead section, which is connected to the outermost cemented casing string with a threaded or slip-on weld connection. This section supports the weight of the BOPs while drilling and the weight of the rest of the wellhead during production by transferring the load to the cemented surface casing. Also included in the “A” section is a tapered bowl to accept the hanger and primary seal for the next casing string to be installed. This may be the intermediate casing or the production casing. The “A” section normally has one or two casing

Lesson 6

6-19

outlets to allow communication with the surface casing annulus for pressure monitoring, for the injection of inhibitors, or for killing or cementing in the event of dangerous pressure conditions. An example of a dangerous pressure situation would be a ruptured casing string caused by inadvertently applying bullheading kill pressure to the casing via a hole or breach in the tubing string. The casing valves provide a conduit through which kill fluid can be introduced into the annular space and gas bled off. This procedure was explained in “Procedures for Removing Gas from a Wellbore (Lubricate-and-Bleed Procedures)” on page 3-42. The “B” section, which is flanged to the top of the “A” section, includes a secondary seal at the top of the production string. The secondary seal is used as a backup in case the primary seal of the “A” section fails. The “B” section includes a tapered bowl that holds the tubing hanger and the primary seal for the tubing. Two outlets are provided in the “B” section body. On at least one of them, a valve and a pressure gauge is installed for monitoring pressure in the tubing/casing annulus. The “C” section is flanged to the top of the “B” section. It includes the tubing head, which terminates the tubing string, and the familiar assembly of valves called the Christmas tree. At the bottom of the tree are one or more master valves (in a multiple-string completion, there will be a master valve for each string). The master valve is the main surface-control point for access to the tubulars. It is always fully open when the well is producing or when a workover is in progress. The working pressure of the master valve is sufficient to handle full wellhead pressure, and it can be used to close the well in and allow work on a tree valve or a fitting above it without killing the well. Above the master valve is a flow fitting, which may be a tee or a cross. The wing valve and a choke (not shown in Fig. 6-16) will be attached to one or both sides of the flow fitting and production flows through the fitting. On top of the flow fitting there is often a crown valve or swab valve (not shown) fitted with an adapter for attaching a lubricator for wireline work. A lubricator is a pressure-rated tube that allows a tool string to be lowered into the well while the well is flowing or under pressure. One end of the lubricator is attached to the swab valve; the other end contains a seal assembly that seals against the wireline used to run the tool (see Fig. 6-17).

6-20

Well Control for Workover Operations

Figure 6-17 Wireline surface rig-up

The spool pieces of each wellhead section have alignment screws for aligning the appropriate tubular in the center of the spool. Alignment of the tubular is critical since the bolt-hole alignment for each flange connection depends on the previous tubular being in the center of the spool below it.

Surface Safety Systems The surface safety system, sometimes known as the emergency shutdown system (ESD), is designed to stop production from a well or group of wells in the case of emergency or catastrophe. Fig. 6-18 shows a typical surface safety system found on a production platform. A pneumatic safety valve, installed on a secondary master valve on the tree, serves as a means of shutting in the well at the surface. The subsurface safety valves provide a means of shutting in the wells below the surface. The control panel supplies hydraulic pressure to operate the subsurface safety

Lesson 6

6-21

valves, while a separator on location supplies the required pneumatic pressure. Emergency shutdown valves are located in strategic locations, such as boat landings (offshore installations), location entrance and exit, helicopter pad, and upper decks.

Figure 6-18 Typical surface safety system

Pneumatic Surface Safety Valves A typical pneumatic surface safety valve is shown at the left in Fig. 6-19. The schematic on the right shows the operation of the valve. Control pressure acts on the piston, which compresses the spring and holds the valve open. An open valve is apparent externally because the operating stem is retracted and nearly hidden from view. When the control pressure is vented, the force of the spring returns the valve to the closed position with the stem protruding and thus visible.

6-22

Well Control for Workover Operations

Figure 6-19 Pneumatic surface safety valve and operation

Fusible Plugs and Caps Low-pressure fusible plugs (Fig. 6-20) contain a material that will melt in the case of fire or excessively high temperature. Depending on the selection of the material, the melting point is between 158°F and 600°F. When the material reaches the melting point, control pressure is vented from the surface safety valve chamber and the valve closes.

Lesson 6

6-23

Figure 6-20 Low-pressure fusible plugs

High-pressure fusible plugs (Fig. 6-21) are sometimes installed on the hydraulic control line of the surface-controlled subsurface safety valve. In the presence of excessive temperatures, the eutectic material in the plug melts and hydraulic fluid is vented from the control line, closing the subsurface safety valve.

Figure 6-21 High-pressure fusible plugs

6-24

Well Control for Workover Operations

Wireline-Cutting Valves Wells completed where wireline work will take place may be equipped with wireline-cutting valves. These valves are surface safety valves capable of cutting both slickline and braided line. The safety valve works in the same fashion as a pneumatic safety valve, but uses hydraulic instead of pneumatic pressure to hold the valve open. The spring and gate in the valve are capable of cutting wireline as large as 7/32 inch. Fig. 6-22 illustrates a wireline-cutting operation. Fig. 6-23 shows the components of a typical wireline cutting safety valve.

Figure 6-22 Wireline-cutting operation

Lesson 6

6-25

Figure 6-23 Typical wireline-cutting surface safety valve

Tree Gate Valves Fig. 6-24 shows a typical gate valve found on a production tree. Valve gates and seats need to be checked occasionally because they can develop leaks across their sealing faces due to the erosive effect of fluids. Another possible leak path is around the valve stem as the stem packing wears out. Some models of gate valves have a packing injection port, allowing the injection of sealant to stop these leaks. Whenever a manual gate valve is operated, the crew should count the turns required to open or close the valve. If the turns are insufficient, the valve may not be fully actuated due to an obstruction across the valve gate.

6-26

Well Control for Workover Operations

Figure 6-24 Typical tree gate valve

BOP Equipment BOP equipment, which is used to control the well in the event of a kick, includes the following:

Lesson 6

•

Annular preventers

•

Ram preventers

•

String safety valves

•

Chokes

•

BOP control systems

•

Back-pressure valves

6-27

Annular Preventers The annular preventer, when closed, seals the annular space between the pipe or tubing and the wellbore. Circular, one-piece resilient sealing elements of various designs are used to make the seal (see Fig. 6-25). Annular preventers are often called “annular BOPs” or simply “annular.”

Hydril GK Operating Features

Shaffer Spherical Operating Features

•

•

• •

•

Will close on open hole (not recommended). Sealing assistance is gained from well pressure. Closing pressure must be reduced as wellbore pressure increases. Capable of measuring piston travel to gauge element wear.

• •

Will close on open hole (not recommended). Some sealing assistance is gained from well pressure. No capability for measuring piston travel.

Figure 6-25 Commonly used annular preventers

The design of the annular preventer allows it to accomplish the following:

6-28

•

Close around the complete circumference of a variety of tubing sizes

•

Seal against irregularly shaped completion components

Well Control for Workover Operations

•

Seal around the tubing that is being stripped in under pressure

•

Close on open hole in emergencies

Recommendations for the Installation, Care, and Use of Annular Preventers Although the rig contractor installs, tests, and operates the annular preventer, you should know the procedures for its proper operation and be prepared to step in and give directions when necessary, particularly when safety may be compromised.

Lesson 6

•

The lifting eyes on the annular body are for lifting the annular only and not the entire BOP stack.

•

If visible, check the color code on the annular element. It should correspond to the elastomeric compound that is compatible with the completion or workover fluid being used (see Table 6-1 for a description of the various packer compounds and color codes).

•

Shutoff valves are often placed in the open and close lines (for line testing and isolation purposes). Make sure these valves are fully open whenever the workover is in progress so the annular can be closed if necessary.

•

Verify that there is a spare packing element on location when working in H2S areas. H2S exposure causes a slow hardening of materials and loss of elasticity in most annular elements.

•

Ensure that opening hydraulic pressure is applied to the annular during the workover. This pressure keeps the element packing fully retracted to avoid mechanical damage.

•

Keep the manufacturer’s operating manual on location. This manual contains valuable information about preventer heights (for headroom restrictions), closing fluid requirements, replacement part numbers, internal seal locations, testing, etc.

•

Check the annular manifold pressure gauge for the correct reading according to the equipment operating manual.

6-29

Table 6-1

Packoff Elements for Annular Preventers

Elastomer

Color Band

Supplier Manufacturer s Code Recommended Use

Hydril

Natural Rubber

Black

R

Shaffer

Natural Rubber

Red

1 or 2

Hydril

Nitrile

Red

S

Shaffer

Nitrile

Blue

5 or 6

Cameron

Nitrile

Black

n/a

Hydril

Neoprene

Green

N

Water-based fluids with less than 5% oil and operating temperatures greater than -30°F; suitable for H2S service. Low-temperature operations and water-based fluids. Oil-based muds with aniline points between 165°F and 245°F; suitable for H2S service and operating temperatures greater than 20°F. Oil- and water-based muds; suitable for H2S service. Oil- and water-based fluid; suitable for H2S service. Temperature range from -30°F to 250°F. Oil-based muds with operating temperatures between 20°F and -30°F; suitable for H2S service.

Ram Preventers Ram preventers (Fig. 6-26)—also called “ram BOPs” or simply “rams”—use two opposing pistons (or manual screws) to move two opposing ram blocks into the wellbore. Depending on the geometry and seal arrangement of the ram blocks (see Fig. 6-27), the rams can be used for the following purposes:

6-30

•

Seal around a pipe or tubing of a particular size (pipe rams)

•

Seal around two tubing strings simultaneously (dual or offset rams)

•

Seal around wireline

•

Seal around sucker rods (production rams)

•

Cut tubing or pipe (shear rams)

•

Cut tubing or pipe and then seal the wellbore above the cut (blind/shear rams)

•

Seal an open wellbore (blind rams)

Well Control for Workover Operations

•

Seal around pipe or tubing in a range of sizes (variable-bore rams)

Rams may hold a small amount of pressure from above, but they are primarily designed to hold pressure from below. Rams are shorter in profile than annular preventers, and for this reason, they may be the only type of preventers installed on a well due to headroom restrictions from the rig substructure. In general, rams close more quickly than annulars and require less hydraulic fluid. They should not be closed on pipe tool joints or tubing upset areas; otherwise seal damage will result. Most rams used in workovers have a provision for manually locking them in the closed position, which is desirable during well control operations or when shutting in for the night. Types of ram blocks used in BOPE during workover operations are shown in Fig. 6-27. Several rams used in workover operations are illustrated in Fig. 6-28. Available rams in the sizes typically used in workovers are listed in Table 6-2.

Figure 6-26 Typical ram preventer

Lesson 6

6-31

Figure 6-27 Types of ram blocks

6-32

Well Control for Workover Operations

Wireline BOP (Double E Inc.)

• • • • •

Closes on slick wireline Available up to 15,000 psi working pressure Manual operation Can be equipped with hydraulic operator Equalizing valve available

Production BOP (Double E Inc.)

• • •

Ram blocks available for up to 1-1/2" diameter sucker rods 2,000 psi working pressure Manual operation

Cameron Model U Ram BOP

• • • • •

Workover sizes 7-1/16" and 11" available from 3,000 psi to 15,000 psi working pressure Single and double configuration Manual and hydraulic ram locks available Wellbore pressure assists ram sealing Ram access by hydraulic ram change system

Hydril Sentinel Ram BOP

• • •

Workover sizes 7-1/16" and 11" available in 10,000 psi and 15,000 psi working pressure Ram access by hinged doors Low profile to minimize headroom requirements

Shaffer Model SL Ram BOP

• • • • •

Workover sizes 7-1/16" and 11" available in 10,000 psi and 15,000 psi working pressure Rams lock automatically when closed Ram access by hinged doors Weephole indicates leakage past wellbore seal LWS and LWP models have manual ram locks

Figure 6-28 Commonly used ram preventers

Lesson 6

6-33

Table 6-2

Typical Ram Preventers Used in Workovers

Nominal Size 4-1/16" 3,000 psi 5,000 psi

Working Pressure

10,000 psi

15,000 psi

Shaffer LWS Cameron G-2 Shaffer LWS Cameron G-2 Cameron QRC Cameron QRC

7-1/16"

9"

11"

Shaffer LWP Shaffer LWP Shaffer LWS Cameron U Cameron U Shaffer LWS Shaffer LWS Shaffer LWS Cameron U Cameron U Shaffer SL Cameron U Cameron U Hydril Sentinel Shaffer SL Cameron U Cameron U Hydril Sentinel

Recommendations for the Installation and Use of Ram Preventers Although the rig contractor installs, tests, and operates the rams, the WSS should know the procedures for their proper operation and be prepared to offer guidance and direction when necessary.

6-34

•

Ram preventers can sometimes be installed upside down, rendering them useless for well control operations. Fig. 6-26 shows the correct orientation: the BOP side outlets should be below the imaginary centerline of the ram.

•

When preventers are installed, adequate space must be left for handwheels and handwheel extensions so that personnel can close rams from a safe distance in an emergency.

•

Many Cameron, Shaffer, and Hydril rams have a secondary ram shaft seal to back up the primary ram shaft seal (see Fig. 6-26). Without this secondary ram shaft seal, wellbore pressure may force its way into the hydraulic system if the primary seal leaks. The seal is activated by tightening a threaded plug or screw and forcing plastic material through a check valve into the cavity around the ram shaft. Make sure the crew knows the location of these seals and how to activate them.

Well Control for Workover Operations

•

Secondary seals are not for routine use. If the primary seal has leaked, requiring use of the secondary, the primary seal must be replaced at the first available opportunity after the well control operation is finished.

•

Ram preventers with secondary seals also have weepholes, or “tattletales,” to monitor the condition of the primary seals. A dripping fluid from the weephole indicates a leak in the primary seal. Make sure the crew knows the location of any weepholes on the rams in use, and make sure the holes are not blocked with either debris or capped with a threaded plug.

•

Have the manufacturer’s operating manuals on location. They contain valuable information about preventer heights (for headroom restrictions), closing fluid requirements, replacement part numbers, internal seal locations, weephole locations, ram change procedures, testing, and other topics.

String Safety Valves These valves are used to close off the bore of the tubing or work string in the event of flow. They are available in various designs and configurations.

Full-Opening Safety Valves Full-opening safety valves (Fig. 6-29) generally have an internal ball that is rotated into position manually with a wrench. When open, they have an unrestricted through bore that allows full-bore access and avoids erosion caused by highvelocity fluid. Full-opening safety valves can be made up and included in the string, or they can be used as stab-in valves installed by the crew on top of the tubing string when the well flows through the string. Because of the unrestricted bore, the crew has a fairly good chance of installing this type of valve when fluid is flowing through the tubing. A stab-in valve with the proper end connection to the string in use must be available on the rig floor. The closing wrench must also be available.

Lesson 6

6-35

Figure 6-29 Full-opening safety valves

Inside Blowout Preventers (IBOPs) IBOPs are spring-loaded one-way check valves that seal the bore of the tubing or work string. An internal plunger seals upward against a seat when pressurized from the wellbore while allowing pumping through the valve in the opposite direction. Gray IBOP The most common type of IBOP is the Gray IBOP, or “Gray valve” (Fig. 6-30). When stripping is required, the crew installs the IBOP above a full-opening safety valve. The full-opening valve can then be opened and both valves stripped into the hole. The IBOP will hold back the wellbore pressure and allow circulation through the completion string.

6-36

Well Control for Workover Operations

Figure 6-30 Gray IBOP (“Gray valve”)

Drop-in Check Valve Another type of IBOP is the drop-in check valve, or “dart,” shown in Fig. 6-31. The dart is placed into the string by the rig crew and allowed to fall (or be pumped) through the string, landing and sealing in a special seating nipple installed in the work string. This particular IBOP can be retrieved with wireline methods.

Lesson 6

6-37

Figure 6-31 Drop-in check valve

Wireline-Set Tubing Plugs These valves serve the same purpose as IBOPs, but they are installed with a wireline in one of the landing nipples in the tubing string. If there are no nipples in the completion, these plugs can be set with a device called a collar stop, which holds them in position against the inside of the tubing. Many of these plugs use an internal mandrel, or prong, that is shifted or pulled by wireline to uncover internal ports that equalize pressures across the plug before it is released. Caution should be taken after equalizing and unseating these plugs. Any gas present under the plug behaves like a secondary kick and can cause well flow. There are many manufacturers of these plugs. A typical example is shown in Fig. 6-32.

6-38

Well Control for Workover Operations

The bypass valve inside the plug is held open by the running tool prong to allow fluid bypass when the plug is run through several nipples of the same size.

Figure 6-32 Wireline-set blanking plug

Chokes Chokes are used to control back pressure in the well during well control operations. They are available in both manual (hand-adjustable) and hydraulic remote control types in various pressure ratings. Manual chokes (Fig. 6-33) typically have a tapered stem and a beveled seat that together form an orifice for controlling fluid flow and pressure. Fluid is allowed to flow through the orifice while the amount of back pressure is controlled by by turning the handwheel to adjust the amount of stem that is forced into the seat. The stem and seat are normally made of tungsten carbide, which resists the abrasive effect of the fluids flowing past them under turbulent flow conditions.

Lesson 6

6-39

Hydraulically operated remote chokes (Fig. 6-33) are normally located in the choke and kill manifold, but they are operated from a remote control panel on the rig floor (Fig. 6-34). This enables the choke operator to better communicate with the driller during the kill procedure. Remotely operated choke systems have additional features not found on manual chokes: •

Variable-speed control of choke

•

Both casing and tubing pressure gauges on panel

•

Pump stroke counters on panel

•

Hand-pump operation in emergency

Figure 6-33 Typical manual and remote chokes

6-40

Well Control for Workover Operations

Figure 6-34 Example of control panel for remote choke

Production chokes (Fig. 6-35) are normally attached to the Christmas tree’s wing valve (shown in Fig. 6-16). They serve a purpose similar to their drilling and workover counterparts in that they restrict flow. Production flow can be restricted when the production string has a volume limitation or there is an excessive amount of abrasive solids. Production chokes are of two types: positive and adjustable. Positive chokes use an insert of a desired size to achieve the restriction. Several styles of adjustable production chokes use mechanisms such as dart and seat, needle and seat, and gate and seat to achieve restriction. Fig. 6-35 shows two models by Cameron, a positive choke and an adjustable choke.

Lesson 6

6-41

Figure 6-35 Positive and adjustable production chokes

BOP Control Systems BOP control systems consist of hydraulic control units, accumulators, and remote panels.

Hydraulic Control Units Fig. 6-36 shows a typical hydraulic control unit, sometimes called a “closing unit.” The unit’s main components are as follows:

6-42

•

Hydraulic pumps that supply energy to charge accumulators.

•

Backup pumps, called air pumps, in case of main pump failure. Nitrogen backup systems are also used in some cases as a backup pressure source for the accumulator.

•

A regulator to reduce accumulator pressure to the level of manifold pressure. Manifold pressure operates ram preventers and BOP side outlet valves.

•

A regulator to reduce accumulator pressure to the level required to operate the annular preventers.

•

A hydraulic control manifold that contains the regulated manifold pressure.

Well Control for Workover Operations

•

Four-way control valves on the hydraulic control manifold. These valves route manifold pressure to the appropriate ram preventer or high closing ratio (HCR) valve.

•

A four-way control valve that routes regulated annular pressure to the annular preventer.

•

A bypass valve used to route unregulated accumulator pressure straight to the BOP components when required (e.g., when using shear rams).

•

Connections to accumulators, pumps, motors, and remote panels.

•

Relief valves for pumps.

•

A reservoir for BOP control fluid.

•

Gauges for accumulator, air, manifold, and annular pressure.

•

A flowmeter to indicate fluid volume used to operate preventers and to charge accumulators.

Figure 6-36 Hydraulic control unit (“closing unit”)

Accumulators Accumulator are bottle-shaped steel cylinders that are often mounted on the same skid as the BOP closing unit (see Fig. 6-36). Offshore they can be installed elsewhere on the rig and connected to the closing unit. Accumulators store energy in the form of pressurized BOP control fluid, which is used to open and close BOPs

Lesson 6

6-43

and valves when required. The closing unit pumps BOP control fluid into the bottles, which contain a nitrogen gas precharge. This action compresses the gas, increases its pressure, and traps energy in the control fluid to be used later. The volume of control fluid inside the bottles between the maximum system pressure and a pressure 200 psi above the precharge is called the “useable” volume (see Fig. 6-40). The Schlumberger Well Control Manual requires that the rig’s closing unit supply a significant amount of useable volume and that a test be carried out to verify that this amount is actually being supplied (see “Accumulator Tests” on page 6-51). Because of the 200 psi safety margin, the useable fluid volume is less than the actual fluid volume inside the accumulators.

Figure 6-37 Data needed for calculating useable accumulator volume—BOP stack

6-44

Well Control for Workover Operations

Figure 6-38 Data for calculating useable accumulator volume—closing unit

Figure 6-39 Data for calculating useable accumulator volume—open/close volumes

As shown in Fig. 6-40, useable volume can be calculated with a simplified equation based on the gas law presented earlier (see “The Barrier Concept” on page 2-40). The sample calculation is based on the crew’s implementation of the following Schlumberger procedure, as specified in the Schlumberger Well Control Manual (p. 87). With the charging pump off, have sufficient fluid volume to accomplish the following (with accumulator pressure at least 200 psi above precharge remaining):

Lesson 6

1

Close annular.

2

Close rams (except blind rams).

3

Open all HCRs.

6-45

6-46

4

Reopen annular.

5

Reopen rams.

6

Close all HCRs.

7

Close annular.

8

Open HCR for choke line.

Well Control for Workover Operations

Accumulator Volume Given: Useable volume equation (see step 2 below) BOP stack (from Fig. 6-37) Closing unit below (from Fig. 6-38) Table of open/close volumes (from Fig. 6-39) Find: Number of 10-gallon accumulator bottles required Solution: 1

Add BOP volumes. Annular close

= 4.57

2 pipe rams close (2 × 1.45) = 2.90 Open HCR

= 0.6

Annular open

= 3.21

2 pipe rams open (2 × 1.18) = 2.36

2

Close HCR

= 0.6

Annular close

= 4.57

Open HCR

= 0.6

Total

=19.4 gallons

Determine useable fluid for one accumulator bottle. Useable Volume per bottle (gals) = Bottle Volume (gals) × [(Precharge Pressure ÷ Final Pressure) - (Precharge Pressure ÷ System Pressure)] Useable Volume per bottle (gals) = 10 gals × [(1,000 psi ÷ 1,200* psi) (1,000 psi ÷ 3,000 psi)] = 5 gals *200 psi above precharge

3

Determine total number of bottles required (round up to a whole number). Total no. bottles = 19.4 gal ÷ 5 gals/bottle = 3.88 = 4 bottles

Figure 6-40 Calculations for useable volume

Lesson 6

6-47

Control Panels Control panels such as the one shown in Fig. 6-41 allow the BOPs to be operated away from the closing unit itself. The one shown below is located on the rig floor. On land rigs, similar panels are often placed a safe distance from the rig floor. On offshore locations, additional remote panels are sometimes placed in the toolpusher’s office. Remote panels have a master control that must be activated and held in position while operating the BOPs.

Figure 6-41 BOP control panel

Back-Pressure Valves (BPVs) and Two-Way Check Valves A back-pressure valve (Fig. 6-42) is a check valve that can be installed in the tubing hanger to prevent flow up the tubing while removing the tree and installing the BOPs prior to the workover. It is also installed prior to removing the BOPs and reinstalling the tree after the workover. The design of the valve allows pumping through the valve from the top while holding pressure from below. Another device, a two-way check valve, seals pressure from above or below. A BPV is replaced with the two-way check valve in order to test the BOPs. The design of the two-way check valve allows for bleeding of any trapped pressure from below the valve.

6-48

Well Control for Workover Operations

Figure 6-42 Back-pressure valve

A long rod called a dry rod is used to install and remove either the BPVs or the twoway check valves. The dry rod has right-handed threads on one end to engage valve threads on valves with a similar ID. The OD threads on the valves are left-handed (see Fig. 6-42). Consequently, when removing the valves, the rod is turned to the right until it bottoms out (this action also unseats the check inside the valve and releases any trapped pressure below the valve). Continued turning to the right backs the left-handed OD threads on the BPV out of the tubing hanger. Because pressure may be released during this operation, a lubricator should be used. Injuries and fatalities have occurred when lubricators were not used. Only trained personnel are allowed to install and remove these valves.

BOP Equipment Testing This section presents a reasonable set of BOPE testing parameters adapted from the Schlumberger Well Control Manual and accepted industry guidelines. These parameters are used to verify the acceptability of BOP equipment and control systems.

Lesson 6

6-49

Initial BOP System Pressure Test Upon installation of BOP equipment on a well, the crew should pressure-test the following components: •

BOP stack

•

Choke manifold

•

Kill line and valves

•

Floor safety valves

For all these components, a low-pressure test (200-300 psi) should be carried out first, followed by a high-pressure test. The pressure for the high-pressure test should not exceed the lowest of the following: •

Maximum anticipated surface pressure

•

Wellhead working pressure

•

70% of the minimum internal yield pressure of the casing

If the casing has been de-rated due to wear or damage, this de-rated value should not be exceeded. Check the well records for information about casing and wellhead pressure ratings. Annulars should be tested to 50% of their rating on the highpressure test in accordance with the Schlumberger Well Control Manual. High-pressure tests should be held for 10 minutes with no visible leaks and no loss of pressure once it has stabilized. Low-pressure tests should be held for 5 minutes. The test procedure should specify whether a chart recorder is to be used to record pressures and make a permanent test record. In some areas using a recorder and maintaining a permanent test record is mandatory (e.g., in U.S. government waters). If a recorder is required, make sure it has been calibrated and is certified as accurate. It should also have a one-hour or a four-hour clock to ensure that the line drawn by the recorder’s pen is long enough to interpret a 5- or 10-minute test.

Control System Testing Control system testing should include a check of the nitrogen precharge, an accumulator test, a pump capability test, and a test of open and close hydraulic lines. The accumulator test is a Schlumberger Well Control Manual requirement. The other tests are taken from general industry guidelines. 6-50

Well Control for Workover Operations

Checking the Nitrogen Precharge This test involves measuring the nitrogen precharge in each individual accumulator bottle before the accumulators are charged with fluid. Closing units will most likely be either 1,500, 2,000, or 3,000 psi rated. The associated proper precharge for each unit rating is shown below: Unit Rating

Precharge

1,500 psi

750 psi

2,000 psi

1,000 psi

3,000 psi

1,000 psi

The precharge can be checked offline by rig personnel before the BOPs are nippled up.

Accumulator Tests The accumulator test (see Schlumberger Well Control Manual) checks the condition of the bottles in the accumulator system. The test verifies the useable volume capacity and the capability of the closing unit’s charging pumps. The test procedure is as follows:

Lesson 6

1

Check accumulator pressure gauge for a full charge. (This will be 1,500 psi, 2,000 psi, or 3,000 psi, depending on the unit.)

2

Isolate the charging pump(s) from the accumulator.

3

Position the work string in the stack for a close-in (that is, make sure the tool joint is clear of all rams).

4

Close the annular preventer.

5

Sequentially close each pipe ram (not blind or blind/shear rams).

6

Open all HCR valves.

7

Open the annular preventer.

8

Open each pipe ram.

9

Close all HCR valves.

10

Open the HCR valve on the choke line.

6-51

11

Record the accumulator pressure. It should be at least 200 psi above the precharge. A low final pressure may indicate damaged accumulator bladders, a low precharge, improper regulator settings, or a system with insufficient accumulator volume to meet the Schlumberger requirements (see accumulator volume calculations in Fig. 6-40). You must obtain an exemption to operate with a lower total accumulator volume than the standard.

12

Engage the accumulator pump(s). Record recharge time, which should be less than 15 minutes.

Closing Unit Pump Capability Test This test verifies the ability of the closing unit pump(s) to close in the well if accumulator supply is lost or expended. Each pump should be capable of closing an annular preventer, opening HCR valve(s), and recharging the manifold. The test procedure is as follows: 1

Close the accumulator isolation valves to isolate all bottles from the manifold.

2

If the system has more than one pump, isolate one pump at a time from its power supply.

3

Close the annular preventer and open the HCR valve(s) on the choke line (if installed).

4

Record the times for each pump to close the annular preventer, open HCR(s), and recharge the annular and manifold pressures to 200 psi above the precharge pressure (1,200 psi in a 2,000 or 3,000 psi rated system; 950 psi in a 1,500 psi rated system).

The time recorded should be less than 2 minutes. If not, the crew should check for restrictions in opening and closing lines, plugged fluid strainers, regulator malfunctions, or pump condition.

Control System and Lines Closing and opening lines to each preventer as well as the HCR and the closing unit manifold should be tested to the rating of the system at the start of the workover (1,500, 2,000, or 3,000 psi). Rated pressure is not to be applied to the preventers themselves, only to the lines up to the preventers.

6-52

Well Control for Workover Operations

Test the opening and closing lines against the shutoff valves adjacent to the preventers. If there are no valves, it is acceptable to cap the lines and test to the system rating. After reconnecting, the connection is tested to normal closing pressure only. This test need not be repeated during the workover unless the correct hydraulic operating pressure becomes difficult to maintain—for example, if the system is continually leaking off and the pumps are kicking in.

Periodic Testing The Schlumberger Well Control Manual specifies a pressure test interval for BOPE of 14 days, not to exceed 21 days. A more frequent interval is advisable for workovers. The U.S. government requires a 7-day interval for workover BOPE but allows the 14-day interval for drilling BOPE for federal lands and offshore. The well control incident rate and equipment failure rate are statistically higher in workover operations where well kills are much more frequent. Furthermore, erosive fluids, sand, scale, and debris are often circulated through the system for extended periods of time and can damage the equipment. The following procedure is recommended to ensure that BOP equipment is working properly: •

Every 7 days pressure-test the BOP components, including the stack choke, kill valves, and the floor safety valves. Test to low and high pressure, as in the initial BOP test.

•

Every 7 days pressure-test the choke manifold connections, as in the initial test. The individual valves should be pressure-tested only if warranted.

If any component in the BOP stack or the choke manifold, the choke or kill line, the floor safety valves, or the control unit has been repaired or replaced or if it is not functioning consistently, it should be thoroughly pressure-tested and function-tested before it is put back in service. Consider a daily function test, verifying the mechanical condition and operation of the following components:

Lesson 6

•

All preventers (do not close the blind rams if there is tubing in the BOP stack)

•

Choke and kill stack valves

6-53

•

Choke and kill manifold valves

Testing of Wireline BOPE Industry-accepted test procedures for both slickline and braided or conductor wireline BOP equipment are described in this section. The wireline company will normally provide the necessary power, pumps, test pumps, and test fluid and run the test. The following information will help you evaluate their test procedure for completeness.

Shop Tests The service company should shop-test (i.e., not on the well) both slickline and braided line lubricator assemblies to 1.5 times the working pressure of the equipment every six months. In the shop, the lubricator is assembled with the control head, wireline BOPs, riser sections, and tree connection and then pressuretested as a functional unit. Check the documentation of the test and match the serial numbers in the documents with those on the actual equipment provided.

Tests at the Well Site Test Procedure for Slickline 1

Open and close wireline rams and visually inspect elements for wear.

2

When rigged up, close wireline ram(s) and test to maximum anticipated surface pressure (MASP).

3

Pressure-test the entire lubricator assembly to the rating of the lubricator or the tree, whichever is lower.

4

Repeat this test each time the connection is broken between the wireline BOP and the tree.

Test Procedure for Braided or Conductor Line

6-54

1

Open and close wireline rams and visually inspect elements for wear.

2

When rigged up, close wireline ram(s) around a steel bar and test to 1,000 psi. The bar is used because pressure applied to an actual braided line tends to bleed off into the braid.

Well Control for Workover Operations

3

Pressure-test the entire lubricator assembly to the rating of the lubricator or the tree, whichever is lower. It is normal to have some leakage at the control head.

Vacuum Degasser The vacuum degasser (Fig. 6-43) uses vacuum pressure to extract gas from drilling or completion fluid. The degassed fluid is returned to a pit and the gas is vented.

Figure 6-43 Vacuum degasser

Fig. 6-44 illustrates the degassing operation. Gas-cut fluid enters the vessel through the inlet line. The fluid spills out over the baffle plate and the gas is extracted with assistance from the internal vacuum. Degassed fluid exits the vessel and returns to the tanks while the extracted gas flows up and out of the vent line. The vent line is run to a safe area on the location, typically up the rig’s derrick. The float valve controls the liquid level inside the vessel at the optimum level.

Lesson 6

6-55

Figure 6-44 Degassing operation

Echometer This device is used to determine the top of the liquid level and the number of tubing collars (connections) to that point. The most commonly used version is manufactured by the Echometer company. The proper name of the instrument is the acoustic liquid level strip chart recorder. In the oilfield, however, it is simply called an echometer. The echometer consists of a microprocessor-controlled, dual channel amplifier/ recorder, and a “gun/microphone” wellhead attachment (Fig. 6-45). The gas gun generates an acoustic pulse that travels through the wellbore gas. This pulse reflects from tubing collars as well as the liquid level. The microphone converts the acoustic reflections to an electrical signal. The amplifier/recorder simultaneously processes and filters the signal through two channels and records two traces on a paper strip chart. One channel accents collars, and the other channel accents the liquid level. The operator counts the number of collar reflections to the liquid level and multiplies by the average length of the tubing joints to determine the distance to the liquid level.

6-56

Well Control for Workover Operations

Figure 6-45 Typical echometer

Lesson 6

6-57

6-58

Well Control for Workover Operations

7 WELL CONTROL COMPLICATIONS Lesson Overview This lesson covers the complications that can arise during workover well control operations. It also describes the tools and proven techniques that workover professionals use to solve these problems or minimize their impact.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to:

Lesson 7

•

Describe the tools and procedures used to locate and seal undesired holes in tubing.

•

Describe the tools and methods used to gain tubing-to-casing communication: •

Shifting a sliding sleeve

•

Pulling a gas-lift dummy valve

•

Perforating the tubing

•

Calculate the differential pressure before gaining tubing-to-casing communication.

•

Explain the need for surface pressure stabilization after gaining tubing-to-casing communication. 7-1

•

Describe the potential problems that can arise when reversing gas kicks, including the following: •

Equipment failures

•

Choke operation problems

•

Gas handling

•

Explain the problems that can occur on the choke or work string while circulating.

•

Describe the requirements for handling unexpected changes in gauge readings.

•

Describe consequences of trapped pressure below packers when doing a workover and the techniques for remediating this problem.

•

Describe situations requiring a pump-through string check valve.

Holes in Tubing Holes in the tubing string create undesirable communication, or leaks, between the tubing and casing, which complicates well control operations. Even a relatively simple operation like bullheading can become difficult if leaks have developed between the strings. One of the best ways to seal or pack off the leak is to install a pack-off assembly, which can be conveyed and set by means of either wireline or coiled tubing. The first step in packing off the holes is to locate the area of communication by using a collar stop running tool and a ponytail. The collar stop running tool (Fig. 7-1) is used to install a stop in 8-round tubing (8 rounded threads per inch) to keep wireline and other tools from falling out the end of the tubing if they are inadvertently dropped. The stop is essential with any side-pocket gas-lift work because it prevents the loss of a dropped gas-lift dummy or valve. A ponytail (Fig. 7-1) is a piece of shredded fabric, softline, or similar material that is attached to the collar stop running tool and then run into the well at a fairly slow rate while pressure is gradually bled from the casing. When the shredded material passes one or more holes in the tubing, it gets sucked into the holes, momentarily slowing the tool string or stopping it altogether, depending on the size of the holes. As the WSS, you can record the depth or depths at which the running tool

7-2

Well Control for Workover Operations

encountered the holes and use this information to decide whether to attempt to install a pack-off.

Figure 7-1

Collar stop running tool and ponytail

If it seems feasible to run a pack-off, determine the internal diameters of the downhole safety valve, tubing nipples, and sliding sleeve(s) as well as the internal diameter and drift of the tubing. If there are multiple holes in the tubing, also determine the distance from the uppermost hole to the lowermost hole. This distance can affect the design and installation of the pack-off assembly, which consists of the lower pack-off, the spacer pipe, and the upper pack-off. With the data in hand: 1

Run and set a lower tubing stop (Fig. 7-2) to provide an anchor point for the lower pack-off assembly.

2

Run the pack-off assembly and place it on the tubing stop.

3

Install an upper tubing stop to serve as an upper anchor point.

If the procedure is successful, the holes will be packed off, allowing fluid to be pumped down the spacer pipe while isolating the tubing and casing from each other.

Lesson 7

7-3

Figure 7-2

Pack-off assembly

As Fig. 7-2 shows, the upper and lower pack-offs provide a seal above and below the hole in the tubing. The upper end of the spacer pipe is screwed into the upper pack-off, and the lower portion of the spacer is “stung in” to the lower pack-off. The lower pack-off has a polished-bore receptacle that receives the lower end of the spacer pipe, which is equipped with seals. The pack-off can be tested by bleeding pressure from the casing. If the casing pressure bleeds down and does not build back up, the pack-off is holding pressure.

Tubing-to-Casing Communication In some workover cases, it is preferable to use a circulating kill technique instead of a noncirculating one. A circulating kill technique requires communication, or flow, between the tubing and the casing. The workover crew can establish communication between the two strings with one of the following methods: 7-4

Well Control for Workover Operations

•

Shifting a downhole sliding sleeve to the open position

•

Pulling a gas-lift dummy from a side-pocket mandrel

•

Perforating the tubing

Regardless of the method used, the crew establishes the communication with wireline tools conveyed either by wireline or coiled tubing. Before attempting to establish communication with one of these methods, the WSS and crew must determine whether there is any differential pressure between tubing and casing at the depth of the desired communication. For more information on differential pressure calculations and the impact of this differential on gaining communication at a specific depth, see “Determining Differential Pressure” on page 7-10.

Shifting a Sliding Sleeve to the Open Position The workover crew may use a sliding sleeve to gain tubing-to-casing communication. The crew runs a shifting tool to the sleeve, usually by wireline or coiled tubing, and uses it to move the sleeve to the open position, thus allowing flow from the tubing to the casing (Fig. 7-3). Sliding sleeves are equipped with an equalizing feature. Theoretically this feature allows the sleeve to be shifted with a large tubing-to-annulus differential pressure. In reality, however, there is a possibility the sleeve could be damaged or fail to shift when a large differential exists. Therefore it is recommended that the differential pressure be nearly equalized before attempting the shifting operation. Equalizing is sometimes done by adding pressure to the lower-pressure side with a jumper line from another well or by bleeding pressure from the higher-pressure side. A small amount of differential (50-100 psi) should be left so that when the sleeve is shifted, the wireline operator will be able to see the gauge readings change. This change in pressure is an indicator that the sleeve has successfully shifted. There are two types of sliding sleeves. One type is shifted up to open while the other type is shifted down to open. The WSS should verify the type of sliding sleeve and advise the wireline company so that the appropriate shifting tool will be provided.

Lesson 7

7-5

Figure 7-3

Shifting sliding sleeve to open position

Pulling a Gas-Lift Dummy Valve Gas-lift equipment is installed in wells in anticipation of a decline in formation pressure before recoverable reserves are produced. When side-pocket gas-lift equipment is used, numerous side-pocket mandrels are run in the tubing string as well. Mandrels provide a space for gas-lift dummies or gas-lift valves (Fig. 7-4). If the mandrels are run in the initial completion, dummies are installed. A dummy valve plugs the port in the side pocket so that there is no undesired tubing-toannulus communication. They can be removed at a later date and replaced with the valves. Once the valves are in place, gas is injected in the casing, entering the mandrel through the gas ports. These ports align with other ports on the gas-lift valve. The gas moves through these ports to enter the tubing string. The gas then lightens the 7-6

Well Control for Workover Operations

oil column hydrostatically, allowing the remaining formation pressure to produce the oil.

Figure 7-4

Side-pocket mandrel with gas-lift dummy or valve

Workover crews can also use the ports on side-pocket mandrels to establish communication from tubing to casing when needed. The crew orients a special kickover tool to latch onto and pull the gas dummy or valve from its location in the side pocket (see Fig. 7-5). Once the valve or dummy is out of the pocket, the ports in the pocket are exposed, providing communication from tubing to casing.

Lesson 7

7-7

Figure 7-5

7-8

Extracting dummy valve from side-pocket mandrel

Well Control for Workover Operations

Perforating the Tubing A third method for gaining tubing-to-casing communication is to perforate the tubing. The crew lowers a perforator, with either mechanical or explosive charge, to the desired depth, which is usually as close to a packer as possible. The crew activates the perforator, establishing communication with the casing (see Fig. 7-6).

Figure 7-6

Lesson 7

Perforating the tubing

7-9

Determining Differential Pressure Whatever the method used to gain communication from tubing to casing, it is important that you first determine whether any casing-to-tubing pressure differential exists at the depth of the desired communication. If there is a positive differential (i.e., total annular pressure is greater than total tubing pressure at the depth of interest) from casing to tubing, the wireline tool string could get blown up the hole or the coiled tubing could be forced into sinusoidial buckling, possibly requiring a fishing job. If there is a negative differential (i.e., total tubing pressure at the depth of interest is greater than total annular pressure), it could make shifting a sleeve or pulling a gas-lift dummy difficult or impossible. Furthermore, pulling a gas-lift dummy could result in damage to the fishing neck (a special male connection on the dummy valve that mates with a female connection on a running/retrieving tool). This damage would not only make the dummy impossible to remove in the future but also restrict well production when gas lift is required at a later stage in the life of the well. Fig. 7-7 provides an example of the type of information available to workover crews when they are trying to determine whether pressure differential exists. In this example, there are two possible ways of gaining communication with the annulus: through the sliding sleeve just above the packer and through the gas-lift mandrel farther up the tubing string. Determining the differential at either location (if any exists) requires some knowledge of the fluids in place. Along with this knowledge, the WSS must know the vertical depth of both the sliding sleeve and the gas-lift mandrel as well as the vertical length of the fluid columns in place. Calculations of total pressure at the depth of interest are required for both the tubing and the casing. That is, to determine whether any pressure differential exists, calculate total pressure down to the vertical depth of interest in both the annulus and the tubing and then compare the two numbers. Fig. 7-8 illustrates these calculations. Fig. 7-8 also gives the calculations to be performed before opening the sliding sleeve to allow the well to be circulated dead prior to the workover.

7-10

Well Control for Workover Operations

Figure 7-7

Lesson 7

Information needed to determine tubing-to-casing differential

7-11

Differential Pressure (psi) = Total Annular Pressure (psi) - Total Tubing Pressure (psi) Example: Given: Well information from Fig. 7-7 Find: Tubing-to-annulus pressure differential 1

Calculate Total Annular Pressure. Total Annular Pressure = SICP + (0.052 × Fluid Weightppg × Depthvertical) Total Annular Pressure = 0 psi + (0.052 × 11.1 × 11,518) = 6,648 psi

2

Calculate Total Tubular Hydrostatic Pressure. Part A: Gas Hydrostatic Gas Hydrostatic = Gas Gradient × Lengthvertical Gas Hydrostatic = 0.115 × 4,754 = 546.7 Part B: Oil Hydrostatic Compensate for temperature: (Observed Temp - 60) Observed Density – ------------------------------ = API corrected 10 (112 - 60) 32.5 – ------------ = 27.3 API corrected 10 Calculate Oil Hydrostatic. 141.5 ------------------------- × 0.433 × Length vertical 131.5 + API corrected 141.5 ---------------- × 0.433 × ( 11,518 – 4,754 ) = 2,609.7 = 2,610 psi 131.5 + 27.3

3

Calculate Total Tubular Pressure. SITP + Tubing Hydrostatics 2,800psi SITP + 547psiGasHP + 2,610psi Oil HP = 5,957psi

4

Calculate Differential Pressure. Total Annularpsi - Total Tubularpsi 6648 psi - 5957 psi = 691 psi

Figure 7-8

7-12

Calculations for determining tubing-to-casing differential pressure

Well Control for Workover Operations

If the calculated pressure is a positive number, as in the example in Fig. 7-8, a differential exists from casing to tubing, indicating the possibility that wireline tools will be blown up the hole. To avoid this problem, apply pressure to the tubing to equalize the pressure between tubing and casing or, if possible, bleed pressure from the casing. If the calculated pressure is a negative number, a differential exists from tubing to casing, which means that shifting a sleeve or pulling a gas-lift dummy may be difficult to accomplish. If possible, bleed pressure from the tubing or add pressure to the casing. In either case, some effort should be made to equalize or at least minimize the differential that may be present before attempting to establish communication between the tubing and the casing.

Surface Pressure Stabilization After successful communication between the tubing and casing has been established, surface pressure should be allowed to stabilize. Even after you have performed extensive calculations to predict what the stabilized surface pressures will be, the results of the calculations may be only a “best guess” because the calculations are based on assumed amounts and densities of wellbore fluids. In addition, the formation pressure used in the calculation is not always known with great accuracy. Surface pressures are affected by other factors, such as unknown fluid density in both the tubing and casing, especially in a workover. Over time, the brine in the packer fluid can settle out of solution and find its way to the packer. This settled brine can pack around the sleeve and prevent fluid from flowing through it (see A in Fig. 7-9), making it initially impossible to gain string-to-string communication, even though a communication window has been opened via sliding sleeve, gas-lift equipment, or perforation. This settling may also change the density of the fluid in the annulus and create another unknown factor affecting stabilization. The exact density of the fluids in the tubing may not be known, and if there is a differential from casing to tubing, a U-tube pattern of flow is always a possibility until a pressure equilibrium is established (see B in Fig. 7-9). A U-tube flow can cause gauge readings to change. Moreover, if the well is not shut in, flow occurs

Lesson 7

7-13

from the casing to the tubing instead of from the formation. Accurately interpreting surface pressure indicators becomes very difficult. Before any kill method is attempted, whether circulating or noncirculating, stable surface pressures are essential.

Figure 7-9

7-14

Effect of settled salt and U-tube flow on tubing-to-casing communication

Well Control for Workover Operations

Reversing Gas Kicks A previous lesson explained the concept of reversing gas kicks and presented the associated tubing and casing pressure profiles (see “Reverse Circulation Procedures” on page 3-20). As stated earlier, there is a dramatic and rapid increase in tubing pressure because the gas displaces the tubing at a much faster rate in reverse circulation than in forward (or long-way) circulation. This gas behavior can cause some equipment safety and gas-handling problems.

Backup for the Full-Opening Safety Valve When reversing, a full-opening safety valve is installed in the circulating line between the top of the tubing string and the choke manifold. If, while reversing a gas kick, some component of the circulating line fails, the crew’s first impulse will most likely be to stop the pump and close the choke. This action will not stop the leaking of gas, however, because in reversing, the choke is downstream of the circulating line. The crew will eventually realize this and close the string safety valve, but there is a danger that it will cut out, or wash out, due to the erosive effects of the high-velocity gas. For this reason there should be a backup safety valve installed in the string. Either a low-torque valve or a pneumatically actuated valve can be used (Fig. 7-10). These types of safety valves can be more reliably closed in the presence of a strong flow than a full-opening safety valve. When using the lowtorque valve, keep an operating handle on hand. When using the pneumatic actuator, always have a fusible cap in place to ensure that the valve will close in the event of fire.

Lesson 7

7-15

Figure 7-10 Types of backup safety valves

Chicksan Leak Points In every length of chicksan leaks can occur at the hammer union on each end as well as at the elbow joints (Fig. 7-11). Flanged connections provide a better pressure flow system, but unfortunately they are rarely available. All chicksan lines should be inspected for wear, damage, or other defects before installation. After installation, the lines should be pressure-tested to 20% above the highest anticipated surface pressure. All lines used to direct flow from the tubing to the choke manifold should be clearly marked and roped off. Personnel should remain clear of the area until the well is dead and the kill operation has been completed.

7-16

Well Control for Workover Operations

Figure 7-11 Leak points on typical chicksan

Chokes The chokes, both manual and remotely controlled, are other sources of potential problems during reverse circulation. Remotely controlled chokes, pneumatic or hydraulic, are not known for operating at very fast rates. And manual chokes, which can be somewhat difficult to operate with no pressure on them, can be extremely slow and arduous to operate while under pressure. As shown in the graph of reverse circulation in Fig. 7-12, a fast-acting choke is a must. If the choke cannot be manipulated in a timely fashion, the wellbore may become overpressured or more influx may enter the well, prolonging the kill operation. While reversing out a gas kick, the tubing back pressure must increase at a fairly rapid rate to compensate for the severe loss of hydrostatic pressure from the expanding gas. If the choke cannot keep up (i.e., maintain adequate back pressure), bottomhole pressure will decrease and another kick can occur, making an already serious situation even worse.

Lesson 7

7-17

After the gas has arrived at the surface and is being bled from the well, the annular hydrostatic pressure begins to increase at a rapid rate. As a consequence, the required back pressure must decrease relative to the increasing hydrostatic pressure. If the choke cannot be opened fast enough, the bottomhole pressure will begin to increase, maybe to dangerous levels. In addition, the velocity of both liquids and gases passing through the choke can be quite rapid due to the generally reduced internal diameter of the chicksan lines connecting the work string to the choke manifold. This rapid flow rate can increase the likelihood that the choke will wash out or cut out. In contrast, if the kick is a liquid (oil or water), many of the potential problems described above are not applicable. There will be no severe loss of hydrostatic pressure because liquids do not expand as gas does. Instead of constantly increasing surface pressure, the surface pressure would steadily decline. Realistically, though, a liquid hydrocarbon influx rarely enters the well without some associated gas. So in these cases there will probably be some increase in surface pressure, but not nearly as much as there is with a primarily gas influx.

7-18

Well Control for Workover Operations

Figure 7-12 Choke responses required in reversing gas kick

Atmospheric Degasser If used during reverse circulation, the atmospheric degasser (Fig. 7-13), more commonly known as the “gas buster,” can be a potential problem. The degasser contains baffles arranged in a spiral configuration. As fluid enters the vessel and flows over the baffles, it begins to spin. The heavier fluids gather toward the wall of the vessel while the gas breaks out, rises to the top, and exits through the vent line. The baffles increase the area over which the fluid flows, thus making it easier for the gas to break out of the liquid. The degasser’s efficiency is limited by its working pressure. The working pressure is determined by the hydrostatic pressure of the fluid in the vessel and the back pressure created by the diameter and length of the vent line. The degasser will be most efficient with an adequate liquid seal and a short vent line of a large internal diameter. If flow through the degasser is such that the back

Lesson 7

7-19

pressure exceeds the working pressure, however, the vessel will empty through the dump line, which can create a potential hazard by dispersing gas around equipment and personnel. Should the degasser “blow dry” and disperse the gas, the crew should immediately close the choke and the stop the pump, then refill the vessel. The well can then be brought back on choke but at a slower rate. The degasser should be inspected and verified to be in proper working order before attempting kill operations. It should also be properly sized for the upcoming operation. Refer to the Schlumberger Well Control Manual for sizing requirements and guidelines.

Figure 7-13 Atmospheric degasser

7-20

Well Control for Workover Operations

Problems While Circulating Mechanical problems and equipment failures can occur while circulating kicks. The following section describes these problems and the recommended solutions.

Choke Washout A choke that is washing out or cutting out can be initially difficult to detect, but an alert crew will notice certain warning signs. The first indication that the choke has washed out is its failure to seal when fully closed. Another indication, though not as noticeable, is a pattern of frequent choke adjustments during a stage of the kill operation when such adjustments are not usually required. The solution is simple: change to another choke after isolating the faulty choke using upstream and downstream valves on the choke manifold. After the well is dead, the faulty choke should be repaired, tested, and returned to service. If there is no other choke available, you may have to replace the washed-out choke before proceeding with the kill operation.

Plugged Choke An increase in casing pressure followed by an increase in pump pressure can indicate a plugged choke. Both pressures may rise sharply, and this sharp increase can be very detrimental to the well. Another indicator of a plugged choke is a loss of returns in conjunction with the sharp increase in pressures. Therefore, if the crew notices that the choke has become plugged, they should immediately shut down the pump. As with a washed-out choke, the remedy is to change to another choke after isolating the plugged choke by upstream and downstream valves. Using the second choke, bleed any trapped pressure from the well and continue circulating. Once the well is dead, the plugged choke should be cleaned out. This can be quite hazardous, and in some cases, it would be advisable to turn this operation over to specialists who are equipped to deal with the quantity of solids that may be trapped in the choke body and the resulting high pressure. Any sudden release of pressure or trapped solids could seriously injure or kill personnel nearby.

Lesson 7

7-21

Work-String Washout Like the washed-out choke, a washed-out work string can be somewhat hard to detect at first. In theory, as the string begins to wash out, pump pressure will decline. However, the decline is so gradual that it often goes unnoticed. The hole will continue enlarging until the tubing fails. Another indication of a string washout is the premature return of kill weight fluid if a lighter fluid is being replaced by a heavier one. The floorhands should be made aware that most washouts occur at connections or in slip areas and should watch for any of the telltale signs by inspecting each joint. At the first sign of a washout, the joint in question should be removed from the work string, laid aside, and painted with conspicuous red paint so it is not inadvertently picked up and used again.

Plugged Work String When a work string plugs up, the pump pressure will noticeably increase without an increase in the casing pressure. In fact, the casing pressure may decline a bit along with a decrease in return flow. If this decline takes place, the crew should stop the pump and the choke and shut in the well. The crew can pump up the pressure on the work string to try to free the obstruction. However, pumping up the pressure on the annulus may damage the wellbore and the producing formation and is therefore not recommended. If pumping up the pressure does not remove the obstruction, then begin volumetric well control and plan to perforate the work string to reestablish conventional well control. For a review of this scenario, see “Volumetric Method” on page 3-40.

Unexpected Changes in Gauge Readings If the crew sees any sudden or unexpected changes on the pump or casing gauge, they should carefully check them out before reacting to the changes. For instance, if the pump pressure rises sharply, the natural reaction might be to open the choke to relieve the pressure. But before doing so, the crew should check the readings on the casing gauge. If the casing gauge shows no signs of increase, then the problem

7-22

Well Control for Workover Operations

exists on the work-string side of the well. Opening the choke—that is, reducing back pressure—could allow more influx to enter the well. In short, any irregularities in circulating pressures should lead to an evaluation of both sides of the well to assess the problem. If both gauges are reacting, the problem is likely to be on the casing side of the well. If only the pump pressure is changing, the problem is on the work-string side of the well.

Trapped Pressure below Packers Unseen pressure trapped below packers can have serious well control consequences if the completion is pulled with the pressure trapped. The pressure can be swabbed out of the hole with the completion until the force becomes sufficient to hydraulically “pump” the completion out of the hole. You should ensure that the packer’s bypass ports have been functioned prior to unseating the packer. Doing this relieves trapped pressure by equalizing it above and below the packer. In addition, verify that you have sufficient hydrostatic pressure above the packer to ensure primary well control prior to unseating the packer.

Use of Work-String Check Valve Some completions can be temporarily plugged off with materials such as hydrates, paraffin, wax, sand, or ice (in permafrost areas). High pressure often exists on the opposite side of the obstruction. Penetrating these obstructions with a work string can result in a very dramatic increase in pressure, possibly leading to uncontrolled flow up the tubing. To avoid this uncontrolled flow, you should run a pump-through string check valve into the hole. The check valve sealing assembly can be a plunger type or a flapper type similar to a drilling float. Both seat in landing subs installed in the work string.

Lesson 7

7-23

7-24

Well Control for Workover Operations

8 WSS ROLES AND RESPONSIBILITIES Lesson Overview As the WSS, you have many responsibilities and roles during a workover. You will work primarily through a contractor and service companies that physically perform the work while you manage the operation. You will have financial, administrative, safety, logistics, documentation, and reporting functions as well as everyday decision-making responsibilities. As with most jobs, workovers are done in two phases: a planning phase and an implementation phase. This lesson will explain your responsibilities in each area, with the primary focus on well control. Well control documentation and reporting will also be discussed.

Lesson Objectives After reading this lesson and completing its workbook assignment, you should be able to:

Lesson 8

•

Read and understand a written workover procedure, including typical abbreviations and wellbore schematics.

•

Understand your well control responsibilities in planning and implementing a workover.

•

Document pertinent well control information during and after a workover.

8-1

Planning and Preparation Planning and preparing for a workover operation entails a variety of activities: •

Reviewing and understanding the workover procedure

•

Interpreting correlation logs

•

Coordinating with the production department

•

Communicating with the wireline provider

•

Checking the Christmas tree

•

Reviewing simultaneous operations (SIMOPS)

•

Reviewing the workover procedure with rig personnel

•

Calculating tankage requirements

•

Verifying well control training of contractor personnel

•

Complying with the H2S standard

•

Reviewing BOP test and shut-in procedures

Reviewing the Workover Procedure When a well is to be worked over, a well engineer prepares a workover procedure, a document that describes the entire workover operation. The workover procedure describes in detail the work to be done at the site, including the volume and type of fluid to be used, the equipment to be used, and the steps needed to complete the operation while maintaining well control. The procedure should also contain a detailed schematic drawing of the wellbore, including completion equipment depths, ID’s, connection types, and other matters. For a typical workover procedure, see “Sample Workover Procedure” on page 8-16. The procedure is reviewed and approved by the operations superintendent or project manager. As the WSS, you should review this procedure and cross-check it with historical information, such as wireline reports, previous workover reports, and well test data. You may find that the downhole condition is different from that shown on the procedure with regard to depths, reservoir pressures, location of nipples, presence of fish, pressure limitations on casing due to previous casing patches, and

8-2

Well Control for Workover Operations

other details. It may be necessary to revise the procedure if you discover discrepancies or new information.

Coordinating with the Production Department Before beginning the workover operation, contact the appropriate production field superintendent to discuss the proposed work plans for a particular well and to schedule the well to be shut in. If there are surface or subsurface safety valves, they will have to be scheduled to be taken out of service (see “Subsurface Safety Valves” on page 6-17). In some areas, the disabling of these valves must be approved by and reported to regulatory authorities. If tree valves can be operated from a remote site, the control lines to the valve actuators must be scheduled to be disconnected and tagged in accordance with local lockout/tagout procedures. On gas-lift wells, the gas lift must be scheduled for a shutdown in advance of the workover.

Communicating with the Wireline Provider If a wireline provider is required for a particular well, give the provider the following information based on the workover procedure and well schematics:

Lesson 8

•

The exact well location and name. In a multi-string completion, be sure to identify the string name and associated tree valve.

•

Well status (flowing or shut in) and well pressures.

•

Sizes of tubing and downhole equipment, including ID restrictions.

•

Type of tree connection required for the wireline equipment.

•

Type of wireline work to be performed and a brief review of the procedure.

•

Zero measurement or elevation (for calibration of wireline depth). This measurement is taken using the height of the workover rig floor—sometimes referenced to the rotary kelly bushing (RKB)—as the zero point. As most workover rigs do not have rotary kelly bushings, the zero point is the top of the rotary table. Previous wireline log measurements, which were taken using the drilling rig’s RKB, are used for correlation calibrations for workover operations. The height of the drilling rig’s RKB, in most cases, will be different from the height of the workover rig’s zero point. Correlation corrections to subsurface depths are based on the elevation difference between the workover rig’s zero point and the drilling rig’s RKB at the time the logs were originally obtained.

8-3

•

Presence of any obstructions (such as doglegs).

•

Inspection and testing requirements for wireline equipment.

•

Special safety instructions related to simultaneous operations. Operations such as drilling and workover or workover and production take place simultaneously in some areas, both offshore and land.

•

Lubricator and wireline BOP requirements.

Checking the Christmas Tree Visit the location with a representative from production and perform these steps: 1

Locate the wellhead. (It is possible to rig up on the wrong well on a platform.)

2

In a multiple-string completion, have the production representative identify the proper tree valves for accessing the affected tubing string(s).

3

Determine the type of tree, make of tree, and the make and condition of the tree valves.

4

Determine the status of all strings, whether flowing or shut in.

5

Check for the presence of needle valves and pressure gauges on all completion strings and on casing outlets.

6

Check and record all pressures, including pressure on casing strings.

7

Determine whether the master, crown, and wing valves are operative.

8

Check the status of the surface safety valve (if present). If a surface safety valve is installed, have the production representative verify whether the valve is open or closed. (During a concentric workover, it must be open.) The representative should also specify whether the valve’s automatic close function is to be enabled or disabled during the workover according to client policy.

Reviewing Simultaneous Operations (SIMOPS) In some areas, offshore and land, drilling and production activities may be occurring on wells adjacent to the well that must be worked over. These activities are generally known as simultaneous operations (SIMOPS). The client will have specific SIMOPS procedures and policies, such as requirements for the location and use of emergency shut-down (ESD) stations, which are used to shut in production in

8-4

Well Control for Workover Operations

an emergency. Review all the client’s SIMOPS regulations with the client’s representative and be sure you have a clear understanding of your role.

Reviewing Workover Procedure with Rig Personnel Before the contractor rigs up on a well, you should meet with the contractor’s toolpusher or other representative to discuss the following issues: •

The written workover procedure and the contractor’s scope of work.

•

The correct wellhead to rig up on and the correct string to work on.

•

The status of all strings and casing.

•

The completion configuration downhole.

•

The procedure for bleeding off well pressure and disconnecting the flow line.

•

The well kill procedure and the requirements of the kill fluid.

•

The procedure for nippling up and testing BOPE.

•

Inspection and testing requirements for rig equipment.

•

Safety practices and precautions.

•

Pollution prevention and control.

•

Emergency evacuation procedures.

Calculating Tankage Requirements Tank capacity can be a well control issue if a shortage of capacity limits kill choices. As a rule of thumb, make sure you have sufficient total tank capacity for at least one complete hole volume (annulus plus tubing). This capacity has proven adequate in the field for handling most operations and carrying out the range of kill procedures required. (To review equations for calculating tank capacity, see “Fluid Tank Volumes” on page 2-24.) If a filtered brine is to be used for the kill fluid, additional tankage is required to ensure that the clean brine is not mixed with dirty returns from the well. Hole volumes can be calculated from lengths and diameters given in the written workover procedure using equations in Fig. 2-7 and Fig. 2-8.

Lesson 8

8-5

Verifying Well Control Training You should verify that the rig contractor’s personnel (at least the supervisor and driller) have received formal workover well control training and possess valid certificates. There are two widely accepted certificates for workover well control training: •

Completion/Workover Well Control, Supervisory Level Certificate. This certificate is issued by the International Association of Drilling Contractors (IADC) under the organization’s WellCAP program and is printed with the familiar IADC logo.

•

Completion and Workover Supervisor Certificate. This certificate was issued by the U.S. Minerals Management Service (MMS) prior to 15 October 2002. The MMS no longer issues this certificate.

Each type of certificate is valid for two years. Its expiration date should be checked. A third certifying agency, the International Well Control Forum (IWCF), issues drilling and well intervention well control certificates, but it does not issue workover well control certificates at this time. IWCF well intervention training covers wireline, coiled tubing, and snubbing operations. If these operations are part of the workover, you may require that the wireline, coiled tubing, or snubbing operators possess the appropriate certificate. IADC also issues these certificates, and MMS issued them prior to 15 October 2002.

Complying with the H2S Standard Review Schlumberger’s H2S standard (OFS-QHSE-S015) thoroughly and be prepared to comply with its provisions if the workover is to be carried out in an H2S area. Key points from the document that are relevant to planning and preparation are as follows:

8-6

•

“Each operation in an H2S area shall have a written H2S Emergency Response Plan (ERP). A site contingency plan must be in evidence, with all ERP information posted. Site plans for shut-in and evacuation must be read and understood by Site Supervisor and company personnel prior to rigging up any equipment on location.”

•

“The H2S Contingency Plan shall be tested prior to start-up in suspected or known H2S areas.”

Well Control for Workover Operations

•

•

•

“The H2S Contingency Plan shall be tested periodically by performing H2S drills.” •

H2S drills shall be held at least on a weekly basis when working in a suspected or known H2S area.

•

The drills shall be preplanned and shall emphasize the key learning point(s).

•

The drills shall be held on varying days of the week and at varying times.

“Training shall meet local regulations, Client or OFS requirements.” OFS requirements are as follows: •

Crews working on H2S wells must be certified to H2S level 2 by a qualified instructor.

•

Crews working in nonsuspected H2S areas must have completed H2S level 1.

“Schlumberger’s working limit is max 10 PPM free H2S in the produced gas or in gas associated with produced oil or gas evolving from drilling mud circulated from an H2S well. 10 PPM is the trigger level of our detection equipment. At any concentration above this, special breathing apparatus must be worn, otherwise all work is to be terminated immediately and all personnel evacuated.”

Reviewing BOP Test Procedures Review the rig contractor’s written BOP test procedure for completeness and compliance with Schlumberger’s BOPE test requirements (see “Initial BOP System Pressure Test” on page 6-50).

Conducting Well Control Drills Plan the details of the shut-in and well killing procedures, including the type of BOP and workover equipment, that will be used for this well and inform the contractor so that crew members know what is expected of them. After a drill debrief the crew, pointing out the positive aspects of their performance first and then discussing areas for improvement. Make sure that they understand your expectations. Drills are normally conducted weekly unless poor performance demands a greater frequency. If the rig operates around the clock, drills should be

Lesson 8

8-7

carried out with all crews. Reasonable drill procedures can be adapted from the drilling well control procedures provided in the Schlumberger Well Control Manual. These procedures consist of the following:

While tripping tubing or work string 1

WSS initiates drill by signaling crew that it has begun. Record start time.

2

Driller sets work string in slips.

3

Crew installs and correctly torques floor safety valve on work string.

4

Crew members close safety valve with wrench (observe whether crew knows which way to turn the wrench).

5

Driller simulates annular closure (observe whether driller knows to use master air valve before and during functioning “annular close”).

6

Record finish time.

While circulating 1

WSS initiates drill by signaling crew that it has begun. Record start time.

2

Driller stops rotation (if applicable) and picks up string to predetermined elevation.

3

Driller stops pumps and conducts flow check.

4

WSS says to driller, “The well is flowing.”

5

Driller sounds alarm to crew (observe whether crew responds to alarm).

6

Drillers simulates annular closure (observe whether driller knows to use master air valve before and during functioning “annular close”).

7

Record finish time.

In general, a proficient crew should be able to carry out these steps in two minutes or less. Make sure that the drill results are logged in the daily report.

8-8

Well Control for Workover Operations

Inspecting BOP Equipment Check BOP equipment with the toolpusher using the following checklists:

BOP Stack •

Stack properly installed and braced.

•

BOP bodies installed right side up (choke and kill outlets below centerline).

•

Stack and hydraulic lines free of visible leaks.

•

Hydraulic lines adequately protected.

•

Safe and accessible remote location for operating BOPs.

•

Manual handwheels available for operating ram preventers.

•

Adequate scaffolding available for safe nippling up and down of BOPs, installation of flowline, and similar tasks.

•

Operating manual for rams and annulars available with manufacturer’s information, such as recommended annular closing pressure for stripping, location of ram weepholes, and normal operating pressures.

•

Weepholes on Shaffer ram BOPs not plugged (see “Recommendations for the Installation and Use of Ram Preventers” on page 6-34).

•

BOP test tool (if required) available and inspected.

•

Annular preventer element made of correct chemical compound as indicated by color code (see Table 6-1).

BOP Closing Unit

Lesson 8

•

Switches, four-way valves, regulators, and gauges properly marked.

•

Gauges, sight glasses, and meters functional and in good condition.

•

Piping free of leaks and adequately braced to resist vibration.

•

Adequate fluid level in the control unit.

•

Control handles in proper position (open or closed, not blocked or centered).

•

Blind ram control handle guarded against inadvertent operation.

•

Accumulator, manifold, and annular pressure correct.

8-9

•

Correct accumulator precharge in all bottles.

•

Accumulator bottles not isolated from closing unit with closed valves.

Choke Manifold •

Lines properly anchored to resist vibration and whip.

•

Gauges in good condition and positioned to be visible to choke operator.

•

Equipment free of signs of leaks.

•

All valve wheels or handles in place.

•

Chokes accessible.

•

Valves lubricated and capable of one-man operation.

•

Valve position correct (open or closed).

•

Bypass line (also called the “blow-down line”) lined up to flare pit.

Other •

Inside BOP and work string safety valve with proper connections available on floor.

•

Wrenches to close safety valves available and easily accessible.

•

Pump relief valve calibrated and at correct level for control system rating.

•

Pump relief valve vent line anchored securely.

•

Pump stroke counter (if installed) functional.

•

PVT system and flowmeter (if installed) functional.

Establishing Communication It is your responsibility to establish and maintain positive communication with the contractor and other well-site personnel. Your attitude and conduct will be seen and noticed by the crews and will in turn affect their attitude and performance. Take the necessary time to inform contract personnel what is expected of them. Establish an open-door policy with those under your authority. Be objective, precise, consistent, receptive, and fair in your decisions. Above all, be sure all the crew members fully understand their job assignments.

8-10

Well Control for Workover Operations

Workover Implementation This section explains your duties for each step in the general sequence of a conventional rig workover—i.e., the well is killed and the tree is replaced with a BOP through which the work is done. 1

Kill the well. Your responsibility will begin with the well kill procedure to be used. For review, see Lesson 3, “Well Control Procedures.” Most wells can be bullheaded to kill the tubing side and then circulated with the constant pump pressure method to kill the annulus. You should, however, be familiar with all the kill options in the lesson. During the kill, it’s always a good idea to make yourself available to supervise the entire operation instead of restricting yourself to operating the choke (unless you do not have confidence in the contractor’s experience). Move around the site to observe the crew’s actions and make the following checks:

2

•

Is the fluid being weighted up correctly?

•

Is the fluid being pulled from the correct tank?

•

If a heavy brine is used, is the tank being agitated constantly to avoid salt dropout?

•

Are fluid returns lined up to the separator? Is the separator functioning and free of blockages? Gas should be flowing out the separator vent line.

•

Are there any leaks in any part of the circulating system?

•

Is the choke operator holding the correct pressure? Is the pump operator maintaining the correct pump speed?

•

What are the surface pressure limits? (For review, see “Bullheading Calculations” on page 3-30.) Does the crew know these limits and understand what action to take if the limits are being approached?

•

If casing pressure begins rising while bullheading the tubing, does the crew understand what action to take?

Observe pressure buildup. When the tubing is completely filled with kill weight fluid, observe the SITP for approximately one hour. If there is no buildup, break the chicksan or circulating

Lesson 8

8-11

line and observe the well for flow through the tree wing valve. Also open the appropriate valve on the casing head and check for annulus flow. If you observe flow:

3

•

Shut the casing head valve(s).

•

Shut in the well.

•

Monitor the pressure(s).

•

Consider increasing the fluid density and rekilling the well.

Monitor fluid level. If fluid level drops steadily, consider the following options:

4

•

Refill and keep hole fill with kill pump.

•

Consider decreasing fluid weight (only to the point of near balance). If the initial kill fluid is, say, 200 psi overbalanced, reduce it to 50 psi and try again.

•

Mix and spot a fluid loss pill across the loss zone and continue to monitor (see “Mixing and Spotting a Kill Pill” on page 5-24).

•

Set back the pressure valves and nipple down the tree while filling the hole and accepting the losses.

Install the back-pressure valves. Some BPVs are set with wireline inside the tubing in landing nipples already in the completion. Another style of BPV is set mechanically in the tubing head just below the tree. These mechanical barriers must be in place before you nipple down the tree in step 5. If a wireline BPV is being used, follow this procedure:

5

•

Install the wireline rams and lubricator on top of the tree while monitoring the well.

•

Pressure-test the wireline rams and lubricator assembly.

•

Install the BPV with wireline. Client policy may dictate setting more than one valve.

Nipple down the tree and nipple up the BOP. Make sure that the wellhead service technician is on hand to inspect and service the tree as required. Have additional studs and nuts available in case any of the

8-12

Well Control for Workover Operations

original ones are rusted or damaged. A ring gasket for the tubing head flange should also be available. 6

Remove the BPV. Install a two-way check valve—if the tubing head is designed for this type of valve (Fig. 6-42). The two-way check valve holds pressure from above and allows the BOP stack to be tested. The check valve is threaded exactly like the BPV and fits in the same profile in the tubing head. If a wireline plug-type BPV was used, this step is not required.

7

Test the stack according to the procedure agreed upon with the contractor. Consider the following during the test. •

Make sure that the correct test pressures are achieved and held for the predetermined amount of time.

•

When testing valves, make sure that the crew opens any valves downstream of those being tested. This provides a vent path so that leaks in the tested valves can be detected.

•

Check that the chart recorder (if required) is connected and functioning. You may be required to sign and date the chart. If so, it is prudent to have the test operator and contractor representative sign and date it at the same time. If a test pump is used, be sure all the needle valves are open between the pump and the BOP stack. If not, only the lines are being tested, which does not constitute a valid test.

•

Instruct personnel to stay away from pressurized components. Keep warning signs posted.

8

Perform the workover procedure.

9

Fill the tubing and annulus with the fluids specified in the procedure. The nature of the tubing fluid will vary from well to well. It will depend on how the well is to be brought back on production (e.g., perforated underbalanced, swabbed in, or jetted in with nitrogen). The casing tubing annulus is to be filled with the appropriate packer fluid, which may include bactericides, corrosion inhibitors, pH buffers, and viscosifiers to hold solids in suspension for years. Ensure that the packer fluid has the required properties before displacing it into the annulus. Incorrectly formulated packer fluid can lead to severe casing and tubing corrosion. Inadequate suspension can cause solids to settle on top of the packer, making it extremely difficult to retrieve at the next workover.

Lesson 8

8-13

10

Reinstall the wireline set plugs or BPVs.

11

Nipple down the BOPs.

12

Reinstall the Christmas tree. Witness a new ring gasket being installed in the tubing head adapter flange. The ring groove should be wiped clean and dry before the gasket is installed. Verify that undamaged studs and nuts are used in the connection and that the nuts are tightened evenly and gradually to avoid loading one side of the connection and damaging the ring gasket. If a BPV was used, retrieve it and replace it with a two-way check valve to allow pressure testing.

13

Pressure-test the Christmas tree and flanges. If you are working in an area requiring test documentation, signed chart recordings will be required, as in step 7.

14

Retrieve wireline plugs or BPVs. The well is now ready to be turned back over to production. Important Note: When it is necessary to change operational steps outlined in an approved workover program or procedure, IT IS MANDATORY THAT YOU FOLLOW A MANAGEMENT OF CHANGE PROCESS as per Schlumberger IPM standards (see “IPM Standards” on page A-14 in the Appendix).

Well Control Documentation Your WSS responsibilities include documenting both daily and end-of-job information pertinent to well control.

Daily Information Daily information is required to make sound well control decisions, to manage change, and provide a handover aid for your relief on 24-hour rigs. Daily information includes the following:

8-14

•

Volume and density of kill fluid used.

•

Description of kill procedures, including method used, pressure history, time breakdown, volumes pumped, and any complications such as equipment failure or lost circulation. Well Control for Workover Operations

•

Changes in fluid properties due to surface additions or well influx.

•

All fluid lost, including amount and characteristics.

•

Setting or retrieval of back-pressure valves.

•

All changes in BOP stack configuration, including ram changes.

•

Testing of BOPE.

•

Downhole restrictions encountered (such as those that occur when tripping, running liners, sidetracking, pulling packers, setting wireline tools, etc.).

•

Changes in tubing string configuration in the well, including depths.

•

Details of how well is secured each evening (on daylight rigs).

•

Details of how well is opened each morning (on daylight rigs).

•

Unusual noises, odors, or effluents from the well.

•

All components installed in or removed from the well. The list should include a detailed description with setting depths, ID’s, OD’s, lengths, pressure ratings, manufacturer, model numbers, etc.

End-of-Job Information Remember that the well you just worked over will most likely be worked over again (the average interval in land areas of the United States is about five years). For well control planning purposes on future workovers, it is essential to document the following on the well report:

Lesson 8

•

Formation pressure at each known point.

•

Presence of H2S and concentration.

•

Location and description of fish left in the hole.

•

Any known casing deratings or other pressure limitations.

•

Wellbore configuration.

•

All casing and tubing strings, including their TVDs, measured depths, nominal sizes, weight per foot, and grade.

•

TVD, measured depth, and description of nipples, gas-lift valves, flow control devices, and chemical injection ports.

8-15

•

Location and description of downhole or surface safety valves.

•

Location and description of control lines and/or chemical injection lines.

•

Location and description of downhole pumping devices in artificial-lift wells.

•

Location of each producing zone, including perf intervals, packer depths, and descriptions.

•

Location of any abandoned zones, including depths and details of cement plugs and bridge plugs.

•

Description of packer fluid and density.

•

All lengths, IDs, ODs, fishing neck sizes and lengths, and all connection types throughout the completion.

Sample Workover Procedure The sample workover procedure in this section is based on an actual procedure for a well that was worked over to abandon depleted zones and recomplete to a higher zone. Proprietary information, such as lease details and names of service companies, has been changed or omitted. This procedure is typical in that it contains commonly used abbreviations, informal terms, and, in some cases, insufficient detail. The wellbore schematics for the workover are shown in Fig. 8-1 and Fig. 8-2, followed by a list of abbreviations. After reviewing the procedure, answer the corresponding workbook questions to check your understanding.

Gold Canyon 965- 1A2 Workover Procedure Block: Gold Canyon 965 Lease: OCS - G - 13000 Well No.: 1A2

Objective: Clean out well to the dual packer at 10310'. Squeeze off the I-3 and J-4 sands. Recomplete well as a single in the H-2 sand (non-gravel-packed) with perforations from 8651' to 8673', 8678'-8684', 8696'-8702', shot at 12 SPF with DP charges.

8-16

Well Control for Workover Operations

Rig: Dock:

Lucky Dog 1 Fourchon C-2

Current Status:

Well shut in waiting on rig. SITP: LS-125 psi; SS-1700 psi

API Number: AFE: Surface Location: BHL:

Proprietary Proprietary Proprietary Proprietary

H-2 Sand Expected Production:

Gas

Zone Top Depth (Tvd)

7,750'

Est. Prod Rate— Liquids:

50 bbls/day

MASP from BHPGas Grad.

2,720 psi

Est. Prod. Rate— Gas:

0.05 MMCFPD

BHP@ 9.0 ppg EMW

3,650 psi

MW used to drill zone

NA

Prod. Fluid Gradient (psi / ft)

0.12 (estimated)

MASP (from MW-0.5 ppgPFG)

NA

1. Have a rig move package with pipeline map and site clearance letter on board prior to moving off present location. Shut in wells. Move rig onto location from the northwest. Jack up and skid rig to the H-5 slot and make rig operational. 2. Kill well with 9.6 ppg NaCl water. Set BPVs in long and short string. Use CIW 2" Type H back-pressure valves. Tubing hangers have 2-3/8' EUE 8rd connections on top. Lock open SCSSSV. Nipple down tree. 3. Nipple up BOPs. Install blind rams in middle ram. Install 2-3/8' - 3-1/2' VBR in bottom ram. Install 2-3/8" dual rams in top ram. Test BOPE to 3,500 /5,000 psi. 4. Rig up line and make gauge run to set a magna range plug. Run magna range plug and set in SWS nipple at 10,714'. Test plug to 1,000 psi. Dump 25' of cement on top. 5. Rig up E-line and lubricator on short string. Make jet cut in short string at 10,285'. Rig up on long string and cut tubing at 10,295'.

Lesson 8

8-17

6. Rig up dual slips and elevators and POOH until both SCSSSVs have been laid down. Hang long string off in slips and continue POOH with short string standing back Use 2-3/8' tubing as work string. Have solid protectors and duct tape onboard. If tubing is not good enough for work string use, lay it down. Have it checked for Norm at the dock prior to unloading it from the boat. 7. Change out top rams to 2-7/8" pipe rams and test to 5,000 psi. 8. Make bit and scraper run to top of tubing using the 2-3/8" BTS-8 tubing as a work string. 9. Pick up a 7-5/8", 39-ppf cement retainer on 2-3/8" tubing and TIH to top of the tubing stub at 10,285'. Set retainer and test to 1,000 psi. Squeeze off the J-4 and I-3 sands with 150 cubic feet of 16.2 ppg cement. If possible, squeeze to 1,000 psi over injection pressure. Dump 50' of cement on top of retainer. Reverse out at top of cement plug. 10. Test production casing to 2,800 psi. 11. Pick up a 7-5/8", 39 ppf Model D packer on the work string and RIH to 8,300'. Set packer and test to 1,000 psi. 12. POOH laying down work string. Seal connections with solid protectors and duct tape. 13. Rig up tubing longs. Tubing is 2-7/8", 6.5 ppf, L-8O, ABC Mod. Run 2-7/8" tubing as per completion diagram. Tubing will not be torq-turned or internally tested. Seal assembly will be tested at the shop to 5,000 psi and will have its test chart. It will have a 6' pup joint installed for internally testing the top connection. Tri City Tools will supply the 2-7/8" SCSSSV. Tubing hanger will also have a 6' pup installed and will have been tested. Hanger running thread is a 2-7/8" ABC Mod connection. Have enough tubing or proper crossovers onboard to land tubing string. Sting in and test seals to 1,000 psi. Space out. Pick up and displace annulus with corrosion inhibitor and land tubing string and test annulus to 1,000 psi. (If well is taking fluid, reverse in inhibitor. Discuss final completion fluid weight with office before reversing in inhibitor.) 14. Test tubing to 3,000 psi. 15. Install BPV. 16. Nipple down BOP's and nipple up tree. Pull BPV and install two-way check. Test tree to 5,000 psi. Pull two-way check. 17. Rig up E-line and lubricator with grease injector. Test lubricator to 3,000 psi. Pick up 2" hollow carrier perf guns loaded with 6 SPF of DP charges to perforate the H-2 sand from 8,651 to 8,673' and 8,678' - 8,684' and 8,696' - 8,702' @ 12 SPF. Discuss the use of an underbalance with the office prior to rigging up E-line.

8-18

Well Control for Workover Operations

18. Rig up swab unit and swab in well. Expected production is gas. Clean up well to production facility. Expect a MASP of 2,800 psi. 19. Shut in at SCSSSV and X-mas tree. Hand over the paperwork (5 documents) for the tree and SCSSSV to production operations. Make sure they get it. 20. Prep for rig move.

Lesson 8

8-19

• • • • • • • •

•

Figure 8-1

8-20

Water Depth: 158' Original KBE:111' Original KBE to THF: 49' Rig: Deep Driller 3 Tree: 2-1/16" 5M x 2-1/16" 5M Dual (CIW) Tbg Hgr Conn (Top): 2-3/8" EUE 8rd Tbg Hgr Conn (Btm): 2-3/8" 4.7 ppf, BTS-8 Tubing: 2-3/8", 4.7 ppf, L-80, BTS-8 with Ceram Kote in top 4,650' of tubing Completion Fluid: 10.5 ppg CaCl

Schematic for sample workover procedure (present completion)

Well Control for Workover Operations

• • • • • • • • •

Figure 8-2

Lesson 8

Water Depth: 158' Rig: Lucky Dog 1 KBE: 115' Tree: 2-9/16" 5M x 2-1/16" 5M Tubing Head: 7-1/6" 10M CIW Tbg Hgr Conn (Top): 2-7/8" ABC Mod Box Tbg Hgr Conn (Btm): 2-7/8" ABC Mod Box Tubing: 2-7/8", 6.5 ppf, L-80, ABC Mod Completion Fluid:

Schematic for sample workover procedure (proposed completion)

8-21

Abbreviations and Terminology The following list contains explanations for the abbreviations and terms used in the sample workover procedure. These explanations will help you understand this sample procedure as well as other workover procedures you will be exposed to in the field.

8-22

SPF

Shots per foot

DP Charges

Deep penetration charges

LS

Long string

SS

Short string

MASP from BHP – Gas Grad

This is a calculation of MASP (maximum anticipated surface pressure) based on subtracting the pressure of an annular column full of gas from the known or assumed bottomhole pressure. This calculation is required by regulatory authorities and is based on the conservative assumption that the annulus becomes evacuated of workover fluid and nothing remains but gas.

MASP from MW-0.5ppg-PFG

MASP in this case stands for maximum allowable surface pressure. PFG stands for the fracture gradient of the formation. What is calculated is the maximum allowed casing pressure that, when added to the pressure of the annular fluid, would exert a pressure on the formation equal to its fracture strength (less a 0.5 ppg equivalent). This calculation is required by regulatory authorities for drilling operations but is not applicable in workovers.

MMCFPD

Millions of cubic feet (of gas) per day. (In other procedures, you may see the term MMSCFD, millions of standard cubic feet per day.) A standard cubic foot is a cubic foot of gas at 60°F and 14.7 psi.

Well Control for Workover Operations

CIW

Cameron Iron Works. (The company’s name has been changed to Cameron, but the abbreviation is still commonly used.)

EUE 8rd

External Upset, 8 Round. This is an API (American Petroleum Institute) tubing thread form with 8 rounded threads per inch. The OD of the tubing is upset. See page 5-1 of “Baker Tech Facts” for more detail.

Magna Range Plug A plug that will seal in a range of IDs SWS Nipple

A selective landing nipple

SWN Nipple

A no–go landing nipple

E-line

Electric line (sometimes called “wireline”)

Jet Cut or Jet Cutter A device used to cut tubing using explosive charges

Lesson 8

Norm

Naturally occurring radioactive minerals. Precipitated from produced fluids, these are radioactive materials deposited on the tubing walls as scale. Radioactive levels are tested with a device like a Geiger counter.

BTS-8

An API buttress thread with 8 threads per inch.

Model D

A permanent packer manufactured by Baker Oil Tools

L-8O

The grade and strength of the tubing

ABC Mod L-80

ABC Mod is a tubing coupling modified with an internal machined groove fitted with a Teflon seal.

Torq Turned

A process using a torquing device that makes up the tubing connection to a selected, specific torque and records the torque applied to each connection.

Hollow carrier perf guns

A type of retrievable perforating assembly using guns run on wireline; the opposite of tubing-conveyed or TCP guns, which are nonretrievable.

8-23

Swab Unit

A self-contained unit used to swab the fluids from the inside of the tubing and create an intentional underbalance in order to initiate production. Swab cups are pulled up the inside of the tubing with braided line attached to a hoist similar to a drawworks.

Clean up well

Flow for a period of time to remove debris, contaminated fluids, and formation damage from workover fluid.

KBE

Kelly bushing estimated. A measurement from the rig floor to mean sea level. This measurement will change with each rig.

KBE to THF

A measurement from the rig floor (kelly bushing estimated) to the tubing hanger flange (THF).

Tbg Hgr Conn

Tubing hanger connection.

EOT-WRG

End of tubing, wireline re-entry guide. A wireline re-entry guide is a flared piece attached to the lowest tubing joint. It helps guide wireline tools into the tubing when POOH with wireline.

The sample workover procedure provides you with basic instructions, job steps, and a certain level of detail to work from. The following information, however, is noticeably missing:

8-24

1

The well kill procedure to be used.

2

Desired workover fluid properties, additives, allowable solids, and turbidity limits.

Well Control for Workover Operations

Glossary Accumulator

Annulus Annular preventer Annular capacity Annular capacity factor Annular volume API gravity

A device used in a hydraulic system to store energy or, in some applications, dampen pressure fluctuations. Energy is stored by compressing a precharged gas bladder with hydraulic fluid from the operating or charging system. Depending on the fluid volume and precharge pressure of the accumulator, a limited amount of hydraulic energy is then available independent of any other power source. Well pressure-control systems typically incorporate sufficient accumulator capacity to enable the blowout preventer to be operated with all other power shut down. The space between two concentric objects, such as between the wellbore and casing or between casing and tubing, where fluid can flow. See Blowout preventer (BOP). The unit volume per foot of annular length (bbl/ft) or the total volume (bbls) in the annulus. See also Annular capacity factor. The unit volume per foot of annular length (bbl/ft). Total annular volume (bbls). A scale used in the United States to measure the gravity or density of liquid petroleum products (that is, weight per unit volume). API gravity is expressed in degrees and thus is often called “API degrees.” The lower the number, the denser the oil. See also Relative density.

API water loss

The unwanted migration of the liquid part of a drilling mud or cement slurry into a formation, often minimized by the blending of additives with the mud or cement. Also known as “fluid loss.”

Artificial lift

Any system that adds energy to the fluid column in a wellbore with the objective of initiating and improving production from the well. Artificial lift systems include sucker rod pumps, gas lift, and electrical submersible pumps.

Atmospheric degasser Back-pressure valve (BPV)

Glossary

See Degasser. A type of check valve, typically installed in the tubing hanger, to isolate the production tubing. The back-pressure valve is designed to hold pressure from below, yet enable fluids to be pumped from above, as may be required for wellcontrol purposes.

G-1

Bactericide

Balanced fluid weight Ballooning

Barrier

G-2

An additive that kills bacteria. Bactericides are commonly used in water muds containing natural starches and gums that are especially vulnerable to bacterial attack. Bactericide choices are limited; they must be effective and yet approved by governments and by company policy. The fluid weight equivalent of the formation pressure for a particular well. The loss of whole fluid into preexisting formation fractures while circulating. When circulation stops, the fluid flows back into the wellbore, giving the appearance of a kick. Any impervious material or device that temporarily or permanently prevents the flow of wellbore and reservoir fluids.

Blast joint

A section of heavy-walled tubing that is placed across any perforated interval through which the production tubing must pass, such as may be required in multiple-zone completions. In addition to being heavier than normal completion components, the wall of a blast joint is often treated to resist the jetting action that may result in the proximity of the perforations.

Blind ram

A thick, heavy steel component of a conventional ram blowout preventer. In a normal pipe ram, the two blocks of steel that meet in the center of the wellbore to seal the well have a hole (one-half of the hole on each piece) through which the pipe fits. The blind ram has no space for pipe and is instead blanked off in order to be able to close over a well that does not contain a drill string. See also Blowout preventer (BOP).

Blowout preventer (BOP)

A large valve at the top of a well that can be closed if the crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the crew can usually initiate procedures to increase the mud density until it is possible to open the BOP and retain control of the formation. BOPs come in a variety of styles, sizes, and pressure ratings. Most BOP stacks contain at least one annular BOP at the top of the BOP stack, and one or more ram BOPs below. The sealing element of an annular BOP resembles a large rubber doughnut that is mechanically squeezed inward to seal either pipe (drill collars, drillpipe, casing, or tubing) or the open hole. A ram BOP consists of two halves of a cover for the well that are split down the middle. Large-diameter hydraulic cylinders, normally retracted, force the two halves of the cover together in the middle to seal the wellbore. Other designs have a circular cutout in the middle that corresponds to the pipe diameter so they can seal the well when pipe is in the hole. Annular BOPs can seal a variety of pipe sizes whereas ram BOPs are effective in sealing a more limited range.

Well Control for Workover Operations

BOP control system

A system that creates and sends pressurized hydraulic fluid to open or close rams, annulars, and valves on the BOP stack.

Bottomhole pressure (BHP)

The pressure, usually measured in pounds per square in. (psi), at the bottom of the hole. This pressure may be calculated in a static, fluid-filled wellbore with the equation BHP = MW × Depth × 0.052, where BHP is the bottomhole pressure in pounds per square in., MW is the mud weight in pounds per gallon, Depth is the true vertical depth in feet, and 0.052 is a conversion factor if these units of measure are used. For circulating wellbores, the BHP increases by the amount of fluid friction in the annulus.

Bridge

A wellbore obstruction caused by a buildup of material such as scale, wellbore fill, or cuttings that can restrict wellbore access or, in severe cases, eventually close the wellbore.

Brine

A water-based solution of inorganic salts used as a well-control fluid during the completion and workover phases of well operations. Brines are solids free, containing no particles that might plug or damage a producing formation. In addition, the salts in brine can inhibit undesirable formation reactions such as clay swelling. Brines are typically formulated and prepared for specific conditions.

Bullheading

Capacity factor Check valve

Glossary

Any pumping procedure in which fluid is pumped into the well against pressure. Often the forcible pumping of fluids into a formation, usually formation fluids that have entered the wellbore during a well control event. Though bullheading is intrinsically risky, it is performed if the formation fluids are suspected to contain hydrogen sulfide gas to prevent the toxic gas from reaching the surface. Bullheading is also performed if normal circulation cannot occur, such as after a borehole collapse. The primary risk in bullheading is that the drilling crew has no control over where the fluid goes and the fluid being pumped downhole usually enters the weakest formation. In addition, if only shallow casing is cemented in the well, the bullheading operation can cause wellbore fluids to broach around the casing shoe and reach the surface. This broaching to the surface has the effect of fluidizing and destabilizing the soil (or the subsea floor), and can lead to the formation of a crater and loss of equipment and life. “Cold bullheading” is a term used to describe bullheading when the temperature of the kill fluid is lower than that of the wellbore. A general term describing volume per unit of length (bbls/ft). For example, see Annular capacity factor. A device that allows fluid to flow or pressure to act in one direction only. Check valves are used in a wide variety of oil and gas industry applications as control or safety devices. Check valve designs are tailored to specific fluid types and operating

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conditions. Some designs are less tolerant of debris, while others may obstruct the bore of the conduit or tubing in which the check valve is fitted. Chicksan Choke

Choke washout

A flexible coupling or swivel joint used in high-pressure lines. A device with an orifice installed in a line to restrict the flow rate of fluids or downstream system pressure. Surface chokes are part of the Christmas tree on a well. Chokes are also used to control the rate of flow of the drilling mud out of the hole when the well is closed in with the blowout preventer and a kick is being circulated out of the hole. Adjustable chokes enable the fluid flow and pressure parameters to be changed to suit process or production requirements. Chokes can be manually operated or hydraulically operated from the remote control panel. See Washout.

Circulating bottomhole pressure

See Bottomhole pressure.

Circulating well control procedure

A procedure using the fluid circulating system and having a return path for the fluid.

Christmas tree

An assembly of valves, spools, pressure gauges, and chokes fitted to the wellhead of a completed well to control production. Christmas trees are available in a wide range of sizes and configurations—such as low- or high-pressure capacity and single- or multiple-completion capacity, depending on the type of well and its production characteristics. The Christmas tree provides primary and backup control facilities for normal production and wellbore shut-in. It also incorporates facilities to enable safe access for well intervention operations such as slickline, electric wireline, or coiled tubing.

Closing unit

A generic term given to the hydraulic power pack and accumulators used to control the blowout preventers on a drilling or workover rig.

Coiled tubing

1. A long, continuous length of flexible steel tubing wound onto a reel. The pipe is straightened prior to pushing it into a wellbore and recoiled to spool it back onto the transport and storage spool. Depending on the tubing diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft to 15,000 ft or more in length. 2. A generic term relating to the use of a coiled tubing string and associated equipment. As a well-intervention method, coiled tubing techniques offer several key benefits. The ability to work safely under live well conditions, with a continuous string, enables fluids to be pumped at any time regardless of the position or direction of travel. Installing an electrical conductor or hydraulic conduit further

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Well Control for Workover Operations

enhances the capability of a coiled tubing string and enables relatively complex intervention techniques to be applied safely. Coiled-tubing unit

The equipment for transporting and using coiled tubing, including a reel for the tubing, an injector head to push the tubing down the well, a wellhead blowout preventer stack, a power source (usually a diesel engine and hydraulic pumps), and a control console. The unit allows continuous circulation while it is being lowered into the hole.

Collar stop running tool

A wireline-deployed tool for installing a tubing collar stop.

Completion

The assembly of downhole tubulars and equipment required to enable safe and efficient production from an oil or gas well. See also Recompletion.

Completion fluid

The well-control fluid used during the completion process. Completion fluids are specially prepared to avoid damage to the reservoir formation and completion components. The fluid should be chemically compatible with the reservoir formation and fluids, and should typically be filtered to a high degree to avoid introducing solids to the near-wellbore area.

Completion string

The entire assembly of tubing, packers, flow control devices, and accessories used to complete a well.

Coning Constant pump pressure method Constant tubing pressure method

Encroachment of one reservoir fluid into the area occupied by another, caused by pressure drawdown. A circulating well control procedure whereby bottomhole pressure is held constant through use of a choke to maintain constant pump pressure while circulating. See Constant pump pressure method.

Crystallization temperature

The temperature at which crystals will appear in a brine solution of a given density as it cools.

Degasser

A device that removes air or gases from drilling liquids. A vacuum degasser works by both expanding the size of the gas bubbles entrained in the mud (by pulling a vacuum on the mud). An atmospheric degasser increases the surface area available to the mud so that bubbles escape (through the use of various cascading baffle plates).

Delta force Delta pressure

Glossary

An unbalanced or differential force. An unbalanced or differential pressure.

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Density

The mass or weight of a substance per unit of volume. With drilling fluids, density is typically reported in pounds per barrel. See also API gravity.

Density cut

A reduction in the density of the wellbore fluid caused by the invasion of formation fluid.

Differential force

See Delta force.

Differential pressure

Displacement

In general, a measurement of fluid force per unit area (measured in units such as pounds per square in.) subtracted from a higher measurement of fluid force per unit area. This comparison could be made between pressures outside and inside a pipe, a pressure vessel, before and after an obstruction in a flow path, or simply between two points along any fluid path, such as two points along the inside of a pipe or across a packer. The process of adding liquid in order to reduce the solids content and maintain the properties of the fluid in the active system. The act of removing one fluid (usually liquid) from a wellbore and replacing it with another. This is accomplished by pumping a spacer fluid that is benign to both the first and second fluid, followed by the new fluid, down the drill string and out the bottom of the drill string or bit. While the spacer and second fluid are pumped into the top of the wellbore, the first fluid is forced out of the annulus between the drill string and the wellbore or casing. In some cases, this general procedure may be reversed by pumping in the top of the annulus and taking fluid back from the drill string. Since this is the reverse of the normal circulation path, this is referred to as “reversing out” or “reverse circulation.”[

Displacement factor

The volume of wellbore fluid that a foot of tubular displaces or pushes out of the way.

Displacement volume

The total volume that a tubular string displaces.

Dilution

Drawdown Drilling break

Dry pipe

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See Pressure drawdown. A sudden increase in rate of penetration while drilling or milling. When the increase is significant, it may indicate a formation change, a change in the pore pressure of the formation fluids, or both, and thus warns of a possible kick. A condition during tripping in which the fluid level inside the pipe or work string has fallen to a level below the rig floor so that when the connection is broken, no fluid spills out. Compare Wet pipe.

Well Control for Workover Operations

Dry rod

A long rod that is threaded on one end and used to install or remove the backpressure valve or two-way check valve from the tubing hanger.

Dual (offset) ram

A pipe ram that will seal on two strings of pipe or tubing simultaneously. See also Blowout preventer (BOP).

Dummy valve

A blank gas-lift valve placed in a gas-lift mandrel to isolate the tubing string from the annulus. Gas-lift valves are frequently replaced with dummy valves during intervention work on wells with gas-lift completions.

Dynamic pressure Dynamic pressure loss

The pressure of fluid in motion. Also called “friction pressure.” See Slow circulating rate pressure.

Echometer

A device used to determine the top of the liquid level in the hole and the number of tubing collars to that point.

Equivalent circulating density (ECD)

The effective density exerted by a circulating fluid against the formation that takes into account the pressure drop in the annulus above the point being considered. The ECD is calculated as: d + P/0.052*D, where d is the mud weight (ppg), P is the pressure drop in the annulus between depth D and surface (psi), and D is the true vertical depth (feet). The ECD is an important parameter in avoiding kicks and losses, particularly in wells that have a narrow window between the fracture gradient and pore-pressure gradient.

Equivalent fluid weight

The fluid weight, or density equivalent, of a certain pressure (psi) at a certain True Vertical Depth (feet).

Filter cake

The residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under a pressure. Filtrate is the liquid that passes through the medium, leaving the cake on the medium. Drilling muds are tested to determine filtration rate and filter-cake properties. Also called “mud cake.”

Fish

Anything left in a wellbore, such as junk metal, a hand tool, a length of drillpipe, or other items. Once lost, the object is referred to as simply “the fish.” Typically, anything put into the hole is accurately measured and sketched so that appropriate fishing tools can be selected if the item must be fished out of the hole.

Fishing

The application of tools, equipment, and techniques for the removal of junk, debris, or fish from a wellbore. The key elements of a fishing operation include an understanding of the dimensions and nature of the fish to be removed, the wellbore conditions, the tools and techniques employed, and the process by which the recovered fish will be handled at surface.

Glossary

G-7

Fishing tool

Any special mechanical device used to aid the recovery of equipment lost downhole.

Flow check

A test performed to ensure stable well conditions or the integrity of a plug, valve, or flow-control device. In most cases, the flow check involves observing stable fluid levels or conditions for a prescribed period.

Flow-control device

A category of completion string accessories used to direct, control, or regulate the flow of reservoir fluids (e.g., a plug choke, a selective nipple, a downhole regulator).

Flow coupling

A relatively short, heavy-walled completion component installed in areas where turbulence is anticipated. The additional wall thickness prevents early failures due to erosion in the turbulent flow area. Flow couplings are typically installed above and below completion components, such as landing nipples, that may affect the flow.

Fluid pill

A relatively small volume of specially prepared fluid placed or circulated in the wellbore. Fluid pills are commonly prepared for a variety of special functions, such as a sweep pill prepared at high viscosity to circulate around the wellbore and pick up debris or wellbore fill. In counteracting lost-circulation problems, a lostcirculation pill prepared with flaked or fibrous material is designed to plug the perforations or formation interval losing the fluid.

Formation pressure

The pressure of fluids within the pores of a reservoir, normally hydrostatic pressure, or the pressure exerted by a column of water from the formation’s depth to sea level.

Forward circulation

Circulation down the tubing and up the annulus.

Friction loss Friction pressure Full-opening safety valve Funnel viscosity Fusible cap

G-8

A reduction in the pressure of a fluid caused by its motion against an enclosed surface (such as a pipe). The faster the fluid moves, the greater the loss. See Dynamic pressure. A string safety valve installed by the rig crew that has an unrestricted through bore when the valve is in the open position. See Viscosity. A threaded cap that screws onto a valve bonnet and holds the valve in the open position. In the event of fire, material in the cap will melt and allow the valve stem to move outward, thus closing the valve.

Well Control for Workover Operations

Gas buster

Gas cap

Gas-cap drive Gas drive

Gas expansion

A simple separator vessel used to remove free or entrained gas from fluids circulated in the wellbore, such as mud used during drilling operations. The gas buster typically comprises a vessel containing a series of baffles with a liquid exit on the bottom and a gas-vent line at the top of the vessel. The gas that accumulates in the upper portions of a reservoir where the pressure, temperature, and fluid characteristics are conducive to free gas. The energy provided by the expansion of the gas cap provides the primary drive mechanism for oil recovery in such circumstances. See also Gas-cap drive. Drive energy supplied naturally by the gas cap, which expands and forces oil into the well and to the surface. See also Gas cap, Gas drive, Solution-gas drive. A primary recovery mechanism for oil wells containing dissolved and free gas, whereby the energy of the expanding gas is used to drive the oil from the reservoir formation into the wellbore. A gas-drive production system utilizes the energy of the reservoir gas, identifiable as either as free or solution gas, to produce reservoir liquids. See also Gas-cap drive, Solution-gas drive. An increase in the volume of a gas, corresponding to a decrease in its pressure.

Gas lift

An artificial-lift method in which gas is injected into the production tubing to reduce the hydrostatic pressure of the fluid column. The resulting reduction in bottomhole pressure allows the reservoir liquids to enter the wellbore at a higher flow rate. The injection gas is typically conveyed down the tubing-casing annulus, entering the production train through a series of gas-lift valves. The gas-lift valve position, operating pressures, and gas injection rate are determined by specific well conditions. See also Gas-lift valve.

Gas-lift mandrel

A device installed in the tubing string of a gas-lift well to house gas-lift valves and similar devices that require communication with the annulus. In the conventional gas-lift mandrel, the gas-lift valve is installed as the tubing is placed in the well, so the tubing string must be pulled to repair or replace the valve. In the side-pocket mandrel, the valve is installed and removed by wireline with the mandrel in place. With this design, the installed components do not obstruct the production flow path, enabling access to the wellbore and completion components below.

Gas-lift valve

A valve used in a gas-lift system to control the flow of lift gas into the production tubing conduit. The gas-lift valve is located in the gas-lift mandrel, which also provides communication with the lift gas supply in the tubing annulus. Operation of the gas-lift valve is determined by preset opening and closing pressures in the tubing or annulus, depending on the specific application. See also Gas lift.

Glossary

G-9

Gas migration

Gelled pill Gravel packing

Highpermeability zone Hookwall packer QHSE

HCR valve

Hydraulic control unit

The movement of gas up a closed-in wellbore where it cannot expand. If the gas does not expand, its volume does not change, and therefore its pressure does not change. Gas migration causes an undesirable increase in wellbore pressure. A fluid treated with viscosifiers (thickening agents). The “pill” is displaced across problem zones downhole to reduce fluid losses. A sand-control method used to prevent production of formation sand. In gravel packing a steel screen is placed in the wellbore and the surrounding annulus packed with prepared gravel of a specific size designed to prevent the passage of formation sand. The primary objective is to stabilize the formation while causing minimal impairment to well productivity. An interval or unit of rock that exhibits a higher loss rate than the surrounding rocks, such as a vugular zone or a naturally fractured zone. See also Lowpermeability zone, Permeability. See Mechanically set packer. Abbreviation for “quality, health, safety, and environmental.” These four issues are of paramount importance to the petroleum industry. Adherence to QHSE guidelines is a requirement for operators worldwide and is also dictated by internal policies of most corporations. A hydraulically actuated valve located on a BOP side outlet. The valve’s High Closing Ratio means that a small amount of hydraulic pressure will create a large valve-closing force. A skid-mounted assembly of accumulators, fluid pumps, control valves, regulators, pipe work, and gauges used to operate the blowout preventers.

Hydraulically operated remote choke

See Choke.

Hydraulically set packer

A packer set without mechanical manipulation of the tubing string. See also Packer.

Hydraulic-set

A setting or operating method that uses hydraulic force applied through the tubing or running string to activate a downhole tool. In many cases a drop ball, which lands in a profiled seat, will be used to shift the setting or activation mechanism at predetermined pressures.

Hydrostatic effect

G-10

The action of a downhole force created by hydrostatic pressure. See also Hydrostatic pressure.

Well Control for Workover Operations

Hydrostatic pressure

Influx

1. In geology, the normal, predicted pressure for a given depth, or the pressure exerted per unit area by a column of freshwater from sea level to a given depth. 2. In drilling, the force per unit area caused by a column of fluid. In U.S. oilfield units, this is calculated using the equation P = MW × Depth × 0.052, where MW is the drilling fluid density in pounds per gallon, Depth is the true vertical depth or “head” in feet, and 0.052 is a unit conversion factor chosen such that P results in units of pounds per square in (psi). 3. The pressure at any point in a column of fluid caused by the weight of fluid above that point. Mud weight must be monitored and adjusted to always stay within the limits imposed by the drilling situation. Sufficient hydrostatic pressure (mud weight) is necessary to prevent an influx of fluids from downhole, but excessive pressure must also be avoided to prevent creation of hydraulic fractures in the formation, which would cause lost circulation. The intrusion of formation fluids into the wellbore. See also Kick.

Injection well

A well in which fluids are injected rather than produced, the primary objective typically being to maintain reservoir pressure. Two main types of injection are common: gas and water. Separated gas from production wells or possibly imported gas may be reinjected into the upper gas section of the reservoir. Water-injection wells are common offshore, where filtered and treated seawater is injected into a lower water-bearing section of the reservoir.

Inside blowout preventer (IBOP)

A string valve, installed by the rig crew, that seals and prevents flow up the inside of the tubing or work string. IBOPs are often used in tandem with full-opening safety valves during stripping operations.

Invert emulsion mud

An oil-based fluid in which fresh or salt water is the dispersed phase and diesel, vegetable, or mineral oil is the continuous phase. In other words, it contains “water in oil” as opposed to a true oil-based fluid, which contains “oil in water.”

Kick

A flow of reservoir fluids into the wellbore. The kick is physically caused by the pressure in the wellbore being less than that of the formation fluids, thus causing flow. This condition of lower wellbore pressure than the formation is caused in two ways. First, if the mud weight is too low, then the hydrostatic pressure exerted on the formation by the fluid column may be insufficient to hold the formation fluid in the formation. This can happen if the mud density is suddenly lightened or is not to specification to begin with, or if a drilled formation has a higher pressure than anticipated. This type of kick might be called an underbalanced kick. The second way a kick can occur is if dynamic and transient fluid pressure effects, usually due to motion of the drill string or casing, effectively lower the pressure in the wellbore below that of the formation. This second kick type could be called an induced kick.

Glossary

G-11

Kickover tool

A special tool with an offset, or off-center, section used to run or retrieve devices from side-pocket mandrels.

Kill

To stop a well from flowing or having the ability to flow into the wellbore. Kill procedures typically involve circulating reservoir fluids out of the wellbore or pumping higher density mud into the wellbore, or both. In the case of an induced kick, where the mud density is sufficient to kill the well but the reservoir has flowed as a result of pipe movement, the driller must circulate the influx out of the wellbore. In the case of an underbalanced kick, the driller must circulate the influx out and increase the density of the drilling fluid. In the case of a producing well, a kill fluid with sufficient density to overcome production of formation fluid is pumped into the well to stop the flow of reservoir fluids.

Kill fluid weight

A fluid weight, or density, that will provide hydrostatic pressure equal to or greater than formation pressure. Also called “kill weight.”

Kill pill

A high-density pill spotted downhole to provide additional hydrostatic pressure. See also Fluid pill.

Kill rate pressure

See Slow circulating rate pressure.

Kill-weight fluid

A mud whose density is high enough to produce a hydrostatic pressure at the point of influx in a wellbore and shut off flow into the well. Kill-weight mud, when needed, must be available quickly to avoid loss of control of the well or a blowout.

Landing nipple

A completion component fabricated as a short section of heavy-wall tubular with a machined internal surface that provides a seal area and a locking profile. Landing nipples are included in most completions at predetermined intervals to enable the installation of flow-control devices, such as plugs and chokes. Three basic types of landing nipple are commonly used: no-go nipples, selective-landing nipples, and ported or safety-valve nipples.

Last crystal to dissolve (LCTD)

A method for determining the crystallization temperature of a brine. See also Crystallization temperature.

Lost circulation

G-12

A lack of mud returning to the surface after being pumped down a well. Lost circulation occurs when the drill bit encounters natural fissures, fractures or caverns, and mud flows into the newly available space. Lost circulation may also be caused by applying more mud pressure (that is, drilling overbalanced) on the formation than it is strong enough to withstand, thereby opening up a fracture into which mud flows.

Well Control for Workover Operations

Lowpermeability zone

A formation or zone with limited capacity to accept fluids. See also Highpermeability zone, Permeability.

Lubricate-andbleed procedure

A well control procedure that involves sequentially pumping fluid into the top of a closed-in wellbore and then bleeding gas off. Also known as “lubrication” and “bleed and feed”.

Lubricator

A long, high-pressure pipe fitted to the top of a wellhead or Christmas tree so that tools may be put into a high-pressure well. In workovers, a term initially applied to the assembly of pressure-control equipment used on slickline operations to house the tool string in preparation for running into the well or for retrieval of the tool string on completion of the operation. The lubricator is assembled from sections of heavy-wall tube generally constructed with integral seals and connections. Lubricator sections are routinely used on the assembly of pressure-control equipment for other well-intervention operations such as coiled tubing.

Manual choke

See Choke.

Matrix acidizing

The treatment of a reservoir formation with a stimulation fluid containing a reactive acid. In sandstone formations, the acid reacts with the soluble substances in the formation matrix to enlarge the pore spaces. In carbonate formations, the acid dissolves the entire formation matrix. In each case, the matrix acidizing treatment improves the formation permeability to enable enhanced production of reservoir fluids. Matrix acidizing operations are ideally performed at high rate but at treatment pressures below the fracture pressure of the formation. This enables the acid to penetrate the formation and extend the depth of treatment while avoiding damage to the reservoir formation.

Measured depth (MD)

The length of the wellbore, as if determined by a measuring stick. Except in vertical wells, this measurement is always longer than the true vertical depth of the well due to intentional or unintentional curves in the wellbore. Since the wellbore cannot be physically measured from end to end, the lengths of individual joints of drillpipe, drill collars, and other drill string elements are measured and added together. See also True vertical depth.

Mechanically set packer

A packer that is set and released by movement of the tubing string—either rotation, weight, or tension at the packer. See also Packer.

Milling

Mud rheology

Glossary

The use of a mill or similar downhole tool to cut and remove material from equipment or tools located in the wellbore. Successful milling operations require appropriate selection of milling tools, fluids, and techniques. See Rheology.

G-13

Natural damage Nipple up “No-go” nipple

Damage to a producing well other than mechanical damage to the completion equipment. Natural damage includes such problems as gas or water coning, emulsion blockage, and pore-throat plugging. To put together, connect parts and plumbing, or otherwise make ready for use. This term is usually reserved for the installation of a blowout preventer stack. See Landing nipple.

Overbalance

The amount of pressure (or force per unit area) in the wellbore that exceeds the pressure of fluids in the formation. This excess pressure is needed to prevent reservoir fluids (oil, gas, water) from entering the wellbore. However, excessive overbalance can dramatically slow the drilling process by effectively strengthening the near-wellbore rock and limiting removal of drilled cuttings under the bit. In addition, high overbalance pressures coupled with poor mud properties can cause differential sticking problems. Because reservoir pressures vary from one formation to another, while the mud is relatively constant density, overbalance varies from one zone to another.

Packer

A downhole device used to isolate the annulus from the production conduit, enabling controlled production, injection, or treatment. A typical packer assembly incorporates a means of securing the packer against the casing or liner wall, such as a slip arrangement, and a means of creating a reliable hydraulic seal to isolate the annulus, typically by means of an expandable elastomeric element. Packers are classified by application, setting method, and possible retrievability.

Packer fluid

A fluid that is left in the annular region of a well between tubing and outer casing above a packer. The main functions of a packer fluid are (1) to provide hydrostatic pressure in order to lower differential pressure across the sealing element, (2) to lower differential pressure on the wellbore and casing to prevent collapse, and (3) to protect metals and elastomers from corrosion.

Pack off

To effect hydraulic isolation, either with a sealing device, such as a packer, or with a specialized plastic or fluid, such as a sealing compound.

Pack-off assembly Perforating gun Perforation

G-14

In general, a sealing device (usually made of elastomeric materials) that seals the annular space between one piece of downhole equipment and another. See Perforator. The communication tunnel created from the casing or liner into the reservoir formation, through which oil or gas is produced. The most common method uses jet perforating guns equipped with shaped explosive charges. However, other perforating methods include bullet perforating, abrasive jetting or high-pressure fluid jetting.

Well Control for Workover Operations

Perforator

A device used to perforate oil and gas wells in preparation for production. Fitted with several shaped explosive charges, perforators are lowered to the desired depth and fired to create penetrating holes in casing, cement, and formation. Also known as a “perforating gun.”

Permanent packer

A packer that is designed to be left in the hole because completion life expectancy is long or wellbore conditions are hostile. See also Packer.

Permeability

The ability to transmit fluids, typically measured in darcies or millidarcies. Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.

pH

A measure of the acidity or alkalinity of a substance. The pH scale ranges from 0 to 14—values below 7 are acidic, values above 7 are basic.

Pipe ram

A type of sealing element in high-pressure split-seal blowout preventers that is manufactured with a half-circle hole on the edge (to mate with another horizontally opposed pipe ram) sized to fit around drillpipe. Most pipe rams fit only one size or a small range of pipe sizes and do not close properly around tool joints or drill collars. A relatively new style is the variable-bore ram, which is designed and manufactured to properly seal on a wider range of pipe sizes. See also Blowout preventer (BOP).

Pit gain

An increase in the average level of mud maintained in each of the mud pits, or tanks. If no mud or other substances have been added to the mud circulating in the well, a pit gain is an indication that formation fluids have entered the well and a kick has occurred.

Plastic viscosity Plug Ponytail

See Viscosity. Any object or device that blocks a hole or passageway. A length of shredded fabric, softline, or similar material that is run into a well to detect holes in tubing.

Precharge

A preliminary gas pressurization placed inside an accumulator bladder. Nitrogen gas is typically used. A precharge insures an adequate supply of potential energy to operate BOP equipment and also ensures that the last drop of BOP control fluid exhausted from the accumulator bottle will be at the precharge pressure.

Pressure gradient

The change in pressure per unit of depth, typically in units of psi/ft or kPa/m. Pressure increases predictably with depth in areas of normal pressure. The normal hydrostatic pressure gradient for freshwater is 0.433 psi/ft, or 9.792 kPa/m, and 0.465 psi/ft for water with 100,000 ppm total dissolved solids (typical Gulf Coast

Glossary

G-15

water), or 10.516 kPa/m. Deviations from normal pressure are described as high or low pressure. Pressure drawdown

The differential pressure that drives fluids from the reservoir into the wellbore. The drawdown, and therefore the production rate, of a producing interval is typically controlled by surface chokes. Reservoir conditions, such as the tendency to produce sand, may limit the drawdown that may be safely applied during production before damage or unwanted sand production occurs.

Pressure drop

A loss of pressure that results from friction sustained by a fluid passing through a line, valve, fitting, or other device.

Pressure force

A force created by pressure acting upon an area.

Pressure loss Pressure method

A lubricate-and-bleed procedure using indicated gauge pressure as a process control as opposed to the volume of fluid. Compare Volume method. See also Lubricateand-bleed procedure.

Primary recovery

The first stage of oil production in which natural reservoir drives are used to recover oil, although some form of artificial lift may be required to exploit declining reservoir drives. Compare Secondary recovery.

Primary well control Production ram Proppant

Ram preventer Rathole

Recompletion

G-16

See Friction loss.

See Well control. A ram preventer that seals around sucker rods used in rod-pumped wells. See also Blowout preventer (BOP). Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants (such as resin-coated sand or high-strength ceramic materials like sintered bauxite) may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore. See Blowout preventer (BOP). An extra hole drilled at the end of the well (beyond the last zone of interest), usually of a smaller diameter than the main hole. It ensures that the zone of interest can be fully evaluated, allows for junk, hole fill-in, and other conditions that may reduce the effective depth of the well, and provides space to leave expendable completion equipment, such as the carriers for perforating gun charges. The action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity. See also Completion.

Well Control for Workover Operations

Reducedspeed pump pressure Relative density

See Slow circulating rate pressure.

The ratio of the weight of a given volume of a substance at a given temperature to the weight of the same volume of water at the same temperature. API gravity is derived from relative density. Formerly called “specific gravity.” See also API gravity.

Reverse circulation

The circulation of fluid down the wellbore annulus, with returns being made up the tubing string. Reverse circulation is often used to remove debris from the wellbore since the high fluid flow rate inside the tubing string enables the recovery of large or dense debris particles that are difficult or impossible to remove with conventional (forward) circulation. See also Forward circulation.

Rheology

The science and study of the deformation and flow of matter. The term is also used to indicate the properties of a given fluid, as in mud rheology. Rheology is an important property of drilling muds, drill-in fluids, workover and completion fluids, cements, and specialty fluids and pills. Mud rheology is measured on a continual basis and adjusted with additives or dilution to meet the needs of the operation. I

Rig workover

A workover using a conventional rig with a derrick and a drawworks. The well is typically killed, and the Christmas tree pulled and replaced with a BOP stack that is in place during the workover. See also Workover.

Rig tank volume Running speed

See Tank volume. The speed (in seconds or minutes per stand) at which the pipe or work string is lowered into the hole with the drawworks.

Running tool

A downhole tool used to run and set downhole plugs or similar equipment. The term applies to a range of tools used in workover activities, such as coiled tubing, snubbing, or rig-based applications. However, the term is most commonly associated with slickline operations, referring to the tools used to run and set slickline locks, plugs, and similar downhole equipment.

Seal bore packer

A type of permanent packer that can be configured to allow for the shortening and lengthening of the tubing string, which occurs due to thermal effects in the well. See also Permanent packer.

Secondary recovery

1. the use of waterflooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive. 2. waterflooding of a depleted reservoir. 3. the first improved recovery method of any type applied to a reservoir to produce oil not recoverable by primary recovery methods. Compare Primary recovery.

Glossary

G-17

Secondary well control Selective nipple

See Well control. See Landing nipple.

Shear ram

A blowout preventer (BOP) closing element fitted with hardened-tool steel blades designed to cut the drillpipe when the BOP is closed. A shear ram is normally used as a last resort to regain pressure control of a well that is flowing. Once the drillpipe is cut (or sheared) by the shear rams, it is usually left hanging in the BOP stack, and kill operations become more difficult. The joint of drillpipe is destroyed in the process, but the rest of the drill string is unharmed by the operation of shear rams. See also Blowout preventer (BOP).

Shifting tool

A downhole tool used to adjust the position of sliding sleeves or similar production and completion equipment. Shifting tools are typically run on slickline, although they may be used with coiled tubing in deviated or horizontal wellbores. Shifting tools are generally prepared or dressed for use with a specific model and size of sliding sleeve.

Shut-in bottomhole pressure (SIBHP)

The force per unit area exerted at the bottom of a wellbore when it is closed at either the Christmas tree or the BOP stack. The SIBP is generated by a combination of the hydrostatic pressure from the weight of the liquid in the well and any additional applied pressure. The applied pressure component may be from the formation or from an external source at the surface.

Shut-in casing pressure (SICP)

The pressure of the annular fluid on the casing at the surface when the well is shut in.

Shut-in pressure (SIP)

The surface force per unit area exerted at the top of a wellbore when it is closed at either the Christmas tree or the BOP stack. The pressure may be from the formation or an external and intentional source. The SIP may be zero, indicating that any open formations are effectively balanced by the hydrostatic column of fluid in the well. If the pressure is zero, the well is considered to be dead, and can normally be opened safely to the atmosphere. See also Shut-in casing pressure, Shut-in tubing pressure.

Shut-in tubing pressure (SITP) Side-pocket mandrel Simultaneous operation (SIMOP)

G-18

The indicated pressure on the tubing gauge in the static condition. See Gas-lift mandrel. A term used mainly on offshore platforms, or installations with multiple wellheads, where more than one wellbore is being accessed, such as where a drilling rig, slickline unit, or coiled tubing unit may be operating at the same time. Simultaneous

Well Control for Workover Operations

operations generally have an impact on the installation safety procedures and contingency planning processes. Slickline

Sliding sleeve

A single-strand wireline used to run and retrieve tools and flow-control equipment in oil and gas wells. The single round strand of wire passes through a stuffing box and pressure-control equipment mounted on the wellhead to enable slickline operations to be conducted safely on live wellbores. A completion device that can be operated to provide a flow path between the production conduit and the annulus. Sliding sleeves incorporate a system of ports that can be opened or closed by a sliding component that is generally controlled and operated by slickline tool string.

Slow circulating rate

See Slow circulating rate pressure (SCRP).

Slow circulating rate pressure (SCRP)

The pressure exerted by the mud pump when the pump’s speed is reduced to a speed that is less than the normal circulating rate. An SCRP or several SCRPs are established for use during a kill. Wells are killed at these slower speeds because the process is easier to control, less friction pressure is exerted on the formation, and the rate of gas leaving the wellbore later in the kill is reduced.

Slow pump pressure

See Slow circulating rate pressure (SCRP).

Slow pump rate

See Slow circulating rate pressure (SCRP).

Snubbing

Solution-gas drive

Specific gravity Spotting

Glossary

The process of forcing pipe or tools into the wellbore against pressure (i.e., when the well is shut in and the pipe’s weight is not sufficient to overcome the upward force of the pressure in the wellbore). In workover operations, snubbing is usually accomplished by using hydraulic power to push (or “snub”) the pipe through the stripping head or blowout preventer. In ordinary stripping operations, the pipe falls into the wellbore under its own weight, and no additional downward force is required. See also Stripping. A type of reservoir drive system in which the energy for the transport and production of reservoir fluids is derived from the gas dissolved in the fluid. As reservoir fluids enter the wellbore, changing pressure conditions cause the gas to break from solution to create a commingled flow of gas and liquid that aids production. See also Gas-cap drive, Gas drive. A ratio of the density of a liquid to the density of fresh water. Fresh water, the reference standard, has an specific gravity of 1.0. Pumping a fluid, or fluid interface, into the wellbore and accurately placing it at a given position. Treatment fluids such as cement slurries and stimulation fluids for

G-19

localized treatment often require accurate placement. Correctly calculating and pumping the appropriate volume of displacement fluid while taking account of well production, wellbore returns, and fluid-density variations are key factors in achieving accurate placement of fluids. Stabbing valve

Static bottomhole pressure Static well analysis Stop

A valve that is connected to the work string in the event that the well starts to flow when running or retrieving the string. A stabbing valve is generally kept on the rig floor as a contingency against unexpected well flow. On snubbing operations, a stabbing valve, or safety valve, is kept in the workbasket to protect against tubing plug or back-pressure valve failure. See Bottomhole pressure.

A analysis of wellbore pressures with the well in the static (nonflowing or nonpumping) condition. A device that prevents another device from passing that point.

Storm choke

See Subsurface-controlled subsurface safety valve.

String safety valve

A safety valve made up in the tubing string or work string.

Stripping

The running or retrieving of a tubing string in a well under pressure, using a stripper or similar sealing device to contain well pressure and fluids. Coiled tubing, snubbing, and some specialized workover rig operations can be conducted on live wells using special sealing equipment to safely and reliably contain wellbore pressure and fluids.

Subsurfacecontrolled safety valve

See Subsurface safety valve (SSSV).

Subsurface safety valve (SSSV)

A safety device installed in the upper wellbore to provide emergency closure of the producing conduits in the event of an emergency. Two types of subsurface safety valve are available: surface-controlled and subsurface-controlled. In each case, the safety-valve system is designed to be fail-safe, so that the wellbore is isolated in the event of any system failure or damage to the surface production-control facilities.

Surfacecontrolled subsurface safety valve

See Subsurface safety valve (SSSV).

G-20

Well Control for Workover Operations

Surface indicators

Readings, indications, and other information that is accessible to the crew on the surface as opposed to downhole. Examples include pressure gauge readings, flow indications, tank levels, and gas detector readings.

Surfactant

A chemical that acts as a surface active agent and functions as an emulsifier, dispersant, oil-wetter, water-wetter, foamers, or defoamers.

Surging Swabbing

Tank capacity factor Trip sheet Tripping True vertical depth (TVD)

Tubing capacity

A rapid increase in pressure downhole that occurs when the string is lowered too fast or when the mud pump is brought up to speed after starting. The pulling of formation fluids into the wellbore through a mechanical action that reduces pressure downhole, such as raising the work string or wireline tools. If the pressure is reduced sufficiently, reservoir fluids may flow into the wellbore and toward the surface. A value that indicates, for a particular tank, the volume per unit of tank height or depth (e.g., barrels per foot or gallons per inch). A written record of the actual volume of fluid added to or displaced from the well while tripping as compared to the theoretical volume. The operation of running the string into the wellbore or pulling it out. The vertical distance from the surface straight down to a point at the bottom of the well (usually the current or final depth). TVD is important in determining bottomhole pressures, which are caused in part by the hydrostatic head of fluid in the wellbore. For this calculation, measured depth is irrelevant and TVD must be used. Compare Measured depth. The internal volume of a particular size of tubing per unit of length (bbl/ft).

Tubing plug

A mechanical device that is installed in the completion by wireline methods for the purpose of preventing flow up the tubing.

Tubingretrievable safety valve

A type of safety valve that is integral to the tubing string and thus retrievable only by removing the entire string. Compare Wireline-retrievable safety valve.

Tubing-tocasing communication Turbidity

Glossary

See Communication.

A measure of the amount of suspended particles in a water-based fluid. When measured with a turbidity meter, turbidity is reported in nephelometric turbidity units (NTUs).

G-21

Underbalance

The amount of pressure (or force per unit area) exerted on a formation exposed in a wellbore below the internal fluid pressure of that formation. If sufficient porosity and permeability exist, formation fluids enter the wellbore.

Usable volume

The volume of BOP control fluid in an accumulator in the pressure range between the maximum pressure and the minimum pressure.

U-tube effect

In a U-tube manometer, the height of one leg of fluid changed by altering the density of some of the fluid in the other leg. In a well with tubing in the hole, the string of tubing is one leg and the annulus between the tubing and the wellbore is the other. If a denser fluid goes into the tubing, fluid flows up the annulus, and vice versa. The practice of putting a dense slugging pill in the tubing in order to pull a dry string makes use of the U-tube effect.

Variable-bore ram

A ram preventer that seals around a specific range of tubing sizes. See also Blowout preventer (BOP).

Viscosifier

A thickening agent used in completion and workover fluids.

Viscosity

A property of fluids and slurries that indicates their resistance to flow. The viscosity of a workover fluid can be measured in two ways: funnel viscosity and plastic viscosity. Funnel viscosity, which is measured by the Marsh funnel, is based on the number of seconds it takes for 1,500 ml of the fluid to flow through the funnel. Plastic viscosity, measured with a rheometer, is based on the ratio of shear stress to shear rate and is measured in centipoises (cp).

Volume method

A lubricate-and-bleed well control procedure whereby the volume pumped into the top of the wellbore is recorded. From this recorded volume, the fluid’s hydrostatic pressure is calculated. A portion of the pressure bled off the well is based on this calculated hydrostatic pressure. Compare Pressure method. See also Lubricate-andbleed procedures.

Volumetric method

A means of controlling gas migration in a well that cannot be circulated. Gas is allowed to expand by bleeding calculated volumes of workover fluid through the choke as the gas moves upward toward the surface.

Vugular formation

A rock formation that contains cavities or vugs, such as limestone and other rocks prone to groundwater leaching. Also known as a “vuggy” formation.

Wait-andweight method

Washout

G-22

A well control method that involves shutting in the well and raising the mud weight to the amount required to kill the well. The heavy mud is then circulated into the well while the kick fluids are simultaneously circulated out. A tubing pressure schedule is used to control the process. A hole in the tubing or work string made larger by the erosive effects of highvelocity fluid passing through it.

Well Control for Workover Operations

Waterdrive

A reservoir-drive mechanism whereby the oil is driven through the reservoir by an active aquifer. As the reservoir depletes, the water moving in from the aquifer below displaces the oil until the aquifer energy is expended or the well eventually produces too much water to be viable.

Waterflood

A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells.

Well completion

See Completion.

Well control

The technology of maintaining pressure on open formations (that is, exposed to the wellbore) to prevent or direct the flow of formation fluids into the wellbore. Primary well control focuses on prevention of formation fluid flow by maintaining wellbore hydrostatic pressure equal to or greater than reservoir pressure. If primary well control is lost, secondary well control is implemented to reestablish primary well control. Secondary well control involves the use of the BOP equipment and circulating system along with various well control procedures to circulate fluids in and kick fluids out, restoring the well to balance.

Well intervention

See Well servicing.

Well servicing

The maintenance procedures performed on an oil or gas well after the well has been completed and production from the reservoir has begun. Well service activities are generally conducted to maintain or enhance the well productivity, although some slickline and coiled tubing applications are performed to assess or monitor the performance of the well or reservoir. Also known as “well intervention.”

Wellhead

The surface termination of a wellbore that incorporates facilities for installing casing hangers during the well construction phase. The wellhead also incorporates a means of hanging the production tubing and installing the Christmas tree and surface flow-control facilities for the production phase of the well.

Wet pipe

A condition during tripping in which the fluid level inside the pipe or work string has not fallen to a level below the rig floor so that when the connection is broken, fluid spills out. Compare Dry pipe.

Wireline

A general term used to describe well-intervention operations conducted using single-strand or multistrand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term is commonly used for electric logging and cables incorporating electrical conductors whereas the term slickline often differentiates operations performed with single-strand wire or braided lines.

Glossary

G-23

Wirelineretrievable safety valve

A type of safety valve that is installed and removed using wireline tools. Compare Tubing-retrievable safety valves.

Work string

A generic term describing a tubing string used to convey a treatment or for well service activities. Both coiled and jointed tubing strings are referred to as work strings.

Workover

The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing, or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.

Workover fluid

A well-control fluid, typically a brine, that is used during workover operations. Since the wellbore is in contact with the reservoir during most workover operations, workover fluids should be clean and chemically compatible with the reservoir fluids and formation matrix.

Zero point

The datum or base line for wireline measurements. Sources Schlumberger Oilfield Glossary. Ed. Gretchen Gillis. June 2002. www.glossary.oilfield.slb.com. A Dictionary for the Petroleum Industry. 2nd ed. Austin: Petroleum Extension Service, Division of Continuing Education, University of Texas at Austin, 1997.

G-24

Well Control for Workover Operations

APPENDIX

CHAPTER0

A

P P E N D I X

A

Abbreviations for Chemical Compounds

Appendix

Name of Compound

Abbreviation

Barium Carbonate Barium Sulphate (Barite) Calcium Bromide Calcium Carbonate Calcium Choride Hydrochloric Acid Hydrofluoric Acid Iron Carbonate Methanol Potassium Chloride Sodium Bromide Sodium Chloride Zinc Bromide

BaCO3 BaSO4 CaBr2 CaCO3 CaCl2 HCl HFl FeCO3 Ch4O KCl NaBr NaCl ZnBr2

A-1

A

P P E N D I X

B

Summary of Equations Annular Volume Calculations Annular Capacity Factor (bbls/ft) = [Casing ID (in2) − Tubing OD (in2)] ÷ 1029.4 Annular Volume = Annular Capacity Factor (bbls/ft) × Length (ft) Balanced Fluid Weight (with safety margin) = [Safety Margin (psi) + Formation Pressure (psi)] ÷ TVD (ft) ÷ 0.052 Balanced Fluid Weight = Formation Gradient (psi/ft) ÷ 0.052 Balanced Fluid Weight = Formation Pressure (psi) ÷ TVD (ft) ÷ 0.052 Bullheading Calculations Maximum Tubing Pressure (mechanical limits): Maximum Initial Tubing Pressure (no backup fluid) = Working Burst Pressure − Tubing Hydrostatic Pressure = Working Burst Pressure − (Formation Pressure − SITP) Maximum Final Tubing Pressure (no backup fluid) = Working Burst Pressure − Kill Fluid Hydrostatic Pressure Maximum Initial Tubing Pressure (with backup fluid) = (Working Burst Pressure − Formation Pressure) + Backup Hydrostatic Pressure Maximum Final Tubing Pressure (with backup fluid) = (Working Burst Pressure − Kill Fluid Hydrostatic Pressure) + Backup Hydrostatic Pressure Maximum Tubing Pressure (formation limits): With Formation Fluid in Tubing (before bullheading) = [Formation Fracture Strength (ppg) − Initial Fluid Weight in Tubing (ppg)] × Formation TVD × 0.052)

A-2

Well Control for Workover Operations

With Kill Fluid in Tubing (after bullheading) = [Formation Fracture Strength (ppg) − Kill Fluid Weight in Tubing (ppg)] × Formation TVD × 0.052 Calculations for Lubricate and Bleed Procedures Volume Method: Hydrostatic Pressure per bbl (of lubricated fluid) = Fluid Gradient (psi/ft) ÷ Upper Annular Capy. Factor (bbl/ft) Hydrostatic Increase (by lubricating a number of barrels) = Hydrostatic Pressure per bbl × bbls lubricated Pressure Method: P3 = P12 ÷ P2 where: P1 = SICP before pumping fluid into annulus P2 = Stabilized SICP after pumping fluid into annulus P3 = Pressure required to bleed SICP down Calculations for Volumetric Method Hydrostatic Pressure per Barrel Fluid in Upper Annulus (psi/bbl) = Fluid Gradient (psi/ft) ÷ Upper Annular Capy. Factor (bbl/ft) Volume (bbls) to bleed each cycle or “stairstep” = Range (psi) ÷ Hydrostatic Pressure per Barrel Fluid (psi/bbl) Calculations of Hydrostatic Pressure Effect of Pulling Pipe or Tubing Allowable Pipe Displacement Volume (bbls) = Allowable Pressure Loss (psi) × (Tubing Capacity Factor + Annular Capacity Factor) ÷ [0.052 × Fluid Weight (ppg)] Pipe Length (ft) Equivalent to Allowable Volume Above = (Allowable Volume Above × 2750) ÷ Pipe Weight (ppf)

Appendix

A-3

Circular Cross-Sectional Area (in2) = 0.7854 × Outside Diameter2 Circulating Bottomhole Pressure (psi) Forward Circulation: Circulating BHP (psi) = Hydrostatic Pressure (psi) + Annular Friction Loss (psi) Reverse Circulation: Circulating BHP (psi) = Hydrostatic Pressure (psi) + Tubing Friction Loss (psi) Crude Oil Calculations If observed temperature > 60˚ F: API corrected density

=

(Observed Temp - 60) Observed Density (on hydrometer) – -----------------------------10 If observed temperature < 60˚ F: API corrected density = (60 - Observed Temp) Observed Density (on hydrometer) – -----------------------------10

141.5 Hydrostatic Pressure = ------------------------------ × .433 × TVD ( 131.5 + API corrected )

Cylindrical Rig Tank Calculations Tank Capacity Factor (bbl/ft) = Tank ID (in2) ÷ 1029.4

A-4

Well Control for Workover Operations

Tank Capacity Factor (bbl/in) = Tank ID (in2) ÷ 1029.4 ÷ 12 Tank Volume (bbls) = Tank ID (in2) ÷ 1029.4 × Tank Height (ft) Tank Volume (ft3) = Tank ID (in ÷ 12)2 × 0.7854 × Tank Height (ft) Tank Volume (ft3) = Tank Volume (bbls) ÷ 5.6145 Displacement Calculations Displacement Factor (bbls/ft) = Pipe wt/ft ÷ 2,750 (for steel pipe or tubing) Displacement Factor (bbls/ft) = [Tubing OD (in2) − Tubing ID (in2)] ÷ 1029.4 Displacement Volume (bbls) = Displacement Factor (bbls/ft) × Length (ft) Closed-end Displacement Factor (bbls/ft) = OD (in2) ÷ 1029.4 Equivalent Fluid Weight = Pressure (psi) ÷ TVD (ft) ÷ 0.052 Equivalent Fluid Weight = Pressure Gradient (psi/ft) ÷ 0.052 Final Circulating Pressure (for Weight and Wait method) Final Circulating Pressure (FCP) = SCRP (psi) × Kill Fluid Weight (ppg) ÷ Original Fluid Weight (ppg) Fluid Weight (ppg) = Pressure Gradient (psi/ft) ÷ 0.052 Force Due to Pressure (pounds) = Pressure (psi) × Cross-Sectional Area (in2) Hydrostatic Pressure (psi) = Fluid Weight (ppg) × (0.052) × TVD (ft) Hydrostatic Pressure = Pressure Gradient (psi/ft) ÷ TVD (ft) Hydrostatic Pressure Loss Calculations (Pulling Dry Pipe or Tubing) Fluid Level Drop (ft) = (Tubing Displacement Factor × Length Pulled) ÷ (Annular Capacity Factor + Tubing Capacity Factor) Fluid Level Drop (ft) = [(Tubing wt/ft ÷ 2750) × Length Pulled] ÷ (Casing ID2 − Tubing OD2 ÷ 1029.4) + (Tubing ID2 ÷ 1029.4) Hydrostatic Pressure Loss = Fluid Level Drop (ft) × Fluid Weight (ppg) × 0.052

Appendix

A-5

Hydrostatic Pressure Loss Calculations (Pulling Wet Pipe or Tubing) Fluid Level Drop (ft) = (Tubing Closed-End Displacement Factor × Length Pulled) ÷ Annular Capacity Factor Fluid Level Drop (ft) = [(Tubing wt/ft ÷ 2750) × Length Pulled] ÷ Tubing OD2 ÷ 1029.4 Hydrostatic Pressure Loss = Fluid Level Drop (ft) × Fluid Weight (ppg) × 0.052 Initial Circulating Pressure (for Weight and Wait, Constant Pump Pressure methods) Initial Circulating Pressure (ICP) = SITP (psi) + SCRP (psi) Internal Volume Calculations Capacity Factor (bbl/ft) = ID (in2) ÷ 1029.4 Internal Volume (bbls) = Capacity Factor (bbls/ft) × Length (ft) Kill Fluid Weight (balanced) = (SITP ÷ TVD perfs ÷ 0.052) + Tubing Fluid Weight (ppg) Kill Fluid Weight (overbalanced) = ((Safety Margin (psi) + SITP) ÷ TVD perfs ÷ 0.052) + Tubing Fluid Weight (ppg) Pressure Gradient (psi/ft) = Fluid Weight (ppg) × 0.052 Pump Calculations Actual Pump Output (bbl/stroke) = barrels pumped ÷ strokes recorded Required Pump Speed (spm) = Required Volume Rate (bpm) ÷ Actual PumpOutput (bbl/stroke) Actual Pump Rate (bpm) = barrel increase in tank ÷ minutes pumped Rectangular Rig Tank Volume Calculations Tank Volume (ft3) = Length (ft) × Width (ft) × Depth (ft) Tank Volume (bbls) = Tank Volume (ft3) ÷ 5.61 Tank Capacity Factor (bbls/inch) = Tank Volume (bbls) ÷ Tank Depth (ft) ÷ 12

A-6

Well Control for Workover Operations

Simplified Gas Law P1 × V 1 = P2 × V2

or P2 = P1 × V1 ÷ V2

or V2 = P1 × V1÷ P2

where: P1 = initial gas pressure (psi) P2 = final gas pressure (psi) V1 = initial gas volume (bbls) V2 = final gas volume (bbls) Static Bottomhole Pressure (BHP) = SITP (psi) + Total Tubing Hydrostatic Pressure (psi)

Appendix

A-7

A

P P E N D I X

C

Increasing Density in Multiple-Salt Brines Density Increase in a Multiple-Salt Brine Added Water (total barrels) = Vi × [(Si2 × Wf) ÷ Sf2] − Wi Added Salt (total pounds) = Vi × [(Si2 × Sf1) ÷ Sf2] − Si1 Final Volume = Initial Volume × Si2 ÷ Sf2 Where: Vi = Initial Brine Volume (bbls) Di = Initial Brine Density (ppg) Df = Desired Brine Density (ppg) Si1 = Salt 1 (CaBr2), initial pounds per barrel* Si2 = Salt 2 (CaCl2), initial pounds per barrel* Sf1 = Salt 1 (CaBr2), final pounds per barrel* Si2 = Salt 2 (CaCl2), final pounds per barrel* Wi = Initial water volume per barrel* Wf = Final water volume per barrel* *From Table A-1 Example: Given: 400 barrels of 12.5 ppg CaBr2/CaCl2 brine Find: Pounds of salt and barrels of water to increase density to 14.0 ppg and final volume Solution (from Table A-1): Si1 = 71.08 pounds CaBr2 at 12.5 ppg Si2 = 179.86 pounds CaCl2 at 12.5 ppg Sf1 = 189.58 pounds CaBr2 at 14.0ppg Sf2 = 149.29 pounds CaCl2 at 14.0 ppg Wi = 0.784 barrels at 12.5 ppg Wf = 0.712 barrels at 14.0 ppg Added Water = 400 × [(179.86 × 0.712) ÷ 149.29] − 0.784 = 29.52 bbls Added Salt (CaBr2) = 400 × [(179.86 × 189.58) ÷ 149.29] − 71.08 = 62,928 lbs Final Volume = 400 × (179.86 ÷ 149.29) = 482 bbls A-8

Well Control for Workover Operations

Table A-1

Appendix

Mixing CaBr2/CaCl2 Brine

Density

To Make 1 bbl (42 gal)

(70 degrees F)

Dry CaBr2(lbs)

Dry CaCl2(lbs)

Water (bbls)

11.7 12.0 12.5 13.0 13.5 14.0 14.5 15.0

7.91 31.60 71.08 110.59 150.10 189.58 229.09 268.57

196.16 190.05 179.86 169.67 159.47 149.29 139.10 128.91

0.822 0.807 0.784 0.760 0.736 0.712 0.689 0.665

A-9

A

P P E N D I X

D

Conversion Factors

Note: Gallons are US gallons.

A-10

Well Control for Workover Operations

Note: Gallons are US gallons.

Appendix

A-11

Note: Gallons are US gallons.

A-12

Well Control for Workover Operations

A

P P E N D I X

E

Brine Filtration Units

Figure A-1 Diatomaceous earth filtration unit

Figure A-2 Cartridge filtration unit

Appendix

A-13

A

P P E N D I X

F

IPM Standards

A-14

Reference

Title

InTouch ID

IPM-PO-QAS-001

Corporate QHSE Policy

3286066

IPM-PO-QAS-002

Engineering Policy

3286067

IPM-ST-QAS-001

Document Formatting Standard

3274817

IPM-ST-QAS-002

Project Bridging Document

3286070

IPM-ST-QAS-003

Glossary of QHSE Definitions

3286072

IPM-ST-QAS-004

Management of Change

3286073

IPM-PR-QAS-001

Document Numbering and Control Procedure

3274819

IPM-FO-QAS-001

Management of Change Form

3286075

IPM-CORP-S004

Indemnity and Risk

3286076

IPM-ST-HSE-001

Gas Detection Service and Equipment

3286077

IPM-ST-HSE-002

Life Saving and Evacuation Equipment

3286078

IPM-ST-HSE-003

Simultaneous Operations

3286079

IPM-PR-HSE-004

Hygiene in Camps and Accommodations

3286082

IPM-PR-HSE-005

Preparation of a Simultaneous Operations Manual

3286083

IPM-ST-WCI-001

Well Engineering Management System (WEMS)

3286084

IPM-ST-WCI-002

Information to be Kept on Location

3286085

IPM-ST-WCI-003

Kick Detection Equipment

3286086

IPM-ST-WCI-004

Well Control Equipment Testing Requirements

3286087

IPM-ST-WCI-005

BOP Stack and Diverter Minimum Requirements

3286088

IPM-ST-WCI-006

Well Control Certification

3286089

IPM-ST-WCI-007

Consensus of Well Control Procedures

3286090

IPM-ST-WCI-008

Well Control Drills

3286091

IPM-ST-WCI-009

Casing Liner and Tubing Pressure Testing

3286092

IPM-ST-WCI-010

Minimum Chemical Stocks

3286093

IPM-ST-WCI-011

Kick Tolerance

3286095

Well Control for Workover Operations

Appendix

Reference

Title

InTouch ID

IPM-ST-WCI-012

Barriers

3286096

IPM-ST-WCI-013

Authority during Well Operations

3286098

IPM-ST-WCI-014

Agreement on Specific Well Control Procedures

3286099

IPM-ST-WCI-015

Well Shut-in Method

3286101

IPM-ST-WCI-016

Well Control Method

3286103

IPM-ST-WCI-017

Kick Detection

3286104

IPM-ST-WCI-018

Kick Prevention

3286106

IPM-ST-WCI-019

Constant Bottomhole Pressure

3286107

IPM-ST-WCI-020

Reporting of Kicks

3286108

IPM-ST-WCI-021

Shallow Gas Risk Assessment and Contingencies

3286109

IPM-ST-WCI-022

Well Control while Running Casing

3286110

IPM-ST-WCI-023

Leak Off Test or Shoe Test

3286111

IPM-ST-WCI-024

Procedures for Radioactive Sources

3286112

IPM-ST-WCI-025

Casing and Tubing Design

3286113

IPM-ST-WCI-026

Temporary and Permanent Abandonment

3286114

IPM-ST-WCI-027

Wellbore Surveying and Collision Avoidance

3286115

IPM-ST-WCI-028

Well Control Briefing Standard

3286116

IPM-PR-WCI-002

Contingency Stripping Procedure

3286117

IPM-PR-WCI-003

Testing of Cement Mixing and Pumping Equipment

3286118

IPM-PR-WCI-004

Operational Requirements for Cement Slurries

3286119

IPM-PR-WCI-005

Cement Placement

3286120

IPM-PR-WCI-006

Setting and Verification of Cement Plugs

3286122

IPM-PR-WCI-007

Survey Program Preparation

IPM-PR-WCI-008

Technical and Operational Integrity

3303422

IPM-REF-WCI-001

Derivation of Kick Tolerance Calculation

3286124

A-15

A

P P E N D I X

G

Well Control Worksheets

A-16

Well Control for Workover Operations

Appendix

A-17

A-18

Well Control for Workover Operations

INDEX

CHAPTER0

A Abbreviations in workover procedures 8-22 Accumulator tests 6-51 Accumulators 6-43 Acid stimulation 1-10 Active functions of fluids 5-3 Additives in fluids 5-10 Alarms, disabled 4-6 Annular capacity factor 2-21 Annular preventers installation, care, and use 6-29 overview 6-28 Annular volume 2-21 API gravity 5-5 Artificial-lift equipment, replacing 1-12 Atmospheric degasser 7-19

B Back-pressure valves 6-48 Balanced fluid weight 2-13 Ballooning 4-9 Barrier concept 2-40 Base fluid 5-9 Blast joints 6-17 BOP closing unit, inspecting 8-9 BOP control panels 6-48 BOP control systems overview 6-42 testing 6-50, 6-52 BOP equipment 6-27 inspecting 8-9 periodic testing 6-53 BOP stack, inspecting 8-9 BOP system pressure test, initial 6-50 BOP test procedures, reviewing 8-7 Bottomhole pressure 2-16 Breaks 4-10 Index

Bridge plugs 6-13 Brines clear 5-10, 5-12 crystallization effects on density 5-22 multiple-salt 5-21 overview 5-12 single-salt 5-19 thermal effects on density 5-22 unintentional dilution 5-23 Bullheading 3-28 and gas channeling 3-37 calculations 3-30 cold 3-38 considerations 3-35 guidelines for selecting 3-47 pre-recorded data required 3-29 pressure schedule calculations 3-33 procedure for scenario 3-34 scenario 3-32

C Calcium chloride 5-15 Calculations accumulator volume 6-47 actual pump rate 2-28 allowable displacement volume 2-33 annular capacity factor 2-21 annular volume 2-21 balanced fluid weight 2-13 balanced fluid weight with safety margin 2-14 bottomhole pressure with gas migration 2-44 brine density with thermal correction 5-6 bullheading 3-30, 3-31 bullheading pressure schedule 3-33 capacity factor 2-20 circulating bottomhole pressure 2-36 cross-sectional area 2-37

I-1

differential force 2-39 differential pressure (tubing to annulus) 7-12 displacement 2-23 equivalent fluid weight 2-12 fluid required to decrease brine density 5-21 for well and workover fluid volumes 2-19 hydrostatic pressure 2-9, 2-10 hydrostatic pressure (temperature corrected) 2-11 hydrostatic pressure effect 2-33 hydrostatic pressure loss (dry pipe) 2-31 hydrostatic pressure loss (wet pipe) 2-32 internal volume 2-20 kill fluid weight 2-15 liquid required to reduce density of solidsladen fluid 5-19 pressure force 2-38 pressure gradient 2-10 pump output 2-26 required pump speed 2-27 salt required to increase density of single-salt brine 5-20 static bottomhole pressure 2-16 static well analysis 2-18 tank capacity factor 2-25 tank volume 2-25 temperature correction for density 2-11 volume of expanding gas 2-42 wait-and-weight 3-13 weight of material required to increase density of solids-laden fluid 5-18 well and formation pressure 2-7 Capacity factor 2-20 Carbon dioxide injection 1-11 Casing capacity 2-20 Casing pressure increase 3-36 Check valves two-way 6-48 work-string 7-23 Chicksan leak points 7-16 Choke manifold, inspecting 8-10 I-2

Choke washout 7-21 Chokes 6-39 during reverse circulation 7-17 plugged 7-21 washed-out 7-21 Christmas tree checking 8-4 components 6-19 Circulating problems 7-21 Circulating well control procedures 3-19 constant pump pressure 3-17 overview 3-10 wait-and-weight 3-11 Circulation and well flow 4-9 when reopening daylight rigs 4-5 Clear brine 5-10, 5-12 Closing unit pump capability test 6-52 Communication with well-site personnel 8-10 with wireline provider 8-3 Completion accessories 6-14 Completion fluids components 5-9 function 5-2 properties 5-4 types 5-2 Completion string components 6-7 Concentric workover 1-15 Conditioners in fluids 5-10 Coning gas 1-5 water 1-6 Constant pump pressure method 3-17 procedures 3-18 Constant tubing pressure method 3-39 procedure 3-39 Conventional rig workover 8-11 Conventional workover 1-14 Well Control for Workover Operations

Conversions, well 1-11 Coordination with production department 8-3 Crude oil, hydrostatic pressure of 2-11 Crystallization temperature 5-8 Cut fluid weight 4-10

D Daylight rigs circulating after reopening 4-5 reopening 3-7 shutting in 3-6 Degasser atmospheric 7-19 vacuum 6-55 Delta force 2-38 Density 5-5 Density cut 4-10 Differential force 2-38 Differential pressure 7-10 Dilution of brine 5-23 Displacement volume 2-22 when running tubing or work string 4-8 Displacing to drilling muds 5-25 Documentation, well control 8-14 Drilling breaks 4-10 Drilling muds 5-25 Drop-in check valve 6-37 Dynamic pressure analysis 2-34

E Echometer 6-56 Emergency shutdown system 6-21 Equipment concentric workover 1-15 convention workover 1-14 pump unit workover 1-17 repair or replacement 1-3 wireline workover 1-16 Equivalent fluid weight 2-12 Excess water production 1-6

Index

Excessive gas production 1-5

F Flow couplings 6-17 Fluid density, insufficient 4-2 Fluid loss control of 5-24 downhole 4-5 Fluid loss rate 5-9 Fluid properties and role of WSS 5-16 Fluid tank volumes 2-24 Fluid weight, decrease in 4-10 Fluids active functions 5-3 additives 5-10 base fluid 5-9 clear brine 5-12 completion 5-2 components 5-9 crystallization temperature 5-8 density 5-5 density control 5-17 fracturing 1-10 function 5-2 loss rate of filtrate 5-9 maintaining properties 5-16 oil-based 5-11 pH 5-8 preventive functions 5-3 properties 5-4 solids-laden 5-17 turbidity 5-8 viscosity 5-7 water-based 5-11 weighting material 5-10 workover 5-2 Foams 5-10 Force, pressure 2-37 Forces 2-37 Formation damage, near-wellbore 1-4

I-3

Fracturing, hydraulic 1-10 Friction pressure 2-4 Friction principles 2-5 Full-opening safety valves backup 7-15 overview 6-35 Fusible plugs and caps 6-23

G Gas as base fluid 5-10 at surface 3-50, 4-10 Gas behavior 2-41 expansion in open wellbore 2-41 expansion in wellbore being killed 2-43 migration in closed wellbore 2-43 Gas channeling 3-37 Gas kick pressure profiles when reversing 3-27 reversing 3-20, 7-15 Gas law 2-41 Gas migration controlling 3-38 in closed wellbore 2-43 Gas production, excessive 1-5 Gauge readings, unexpected changes in 7-22 Gradient, pressure 2-9 Gray IBOP 6-36

H H2S standard 8-6 Hangers, tubing 6-11 Hole fill during a trip 4-4 monitoring volume during a trip 4-4 monitoring while pulling 4-7 Holes in tubing 7-2 Hydraulic control units 6-42 Hydraulic fracturing 1-10 Hydrometer, use of 5-6

I-4

Hydrostatic pressure and pressure gradient 2-8 loss when pulling pipe 2-30 of crude oil 2-11 Hydrostatic pressure effect 2-33

I Implementation, workover 8-11 Increasing production 1-10 Injection carbon dioxide 1-11 steam 1-11 waterflood 1-11 Injection wells 1-11 Inside blowout preventers 6-36

K Kick swabbed 3-49 underbalanced 3-50 with check valve in work string 3-49 with work string out of hole 3-50 See also Gas kick, Kicks Kicks causes 4-1 warning signs 4-6 Kill fluid weight 2-14 Kill pill, mixing and spotting 5-24

L Landing nipples 6-14 LCTD method 5-8 Long-way circulation selection guidelines 3-48 Lubricate-and-bleed pressure method 3-45 procedures 3-42 selection guidelines 3-49

Well Control for Workover Operations

M Milling breaks 4-10 Multiple-salt brines 5-21

N Near-wellbore formation damage 1-4 Nitrogen precharge, checking 6-51 Noncirculating well control procedures bullheading 3-28 constant tubing pressure 3-39 lubricate-and-bleed 3-42 overview 3-28 volumetric 3-40

O Oil as base fluid 5-10 at surface 4-10 Overbalance 2-13

P Packer fluid 5-2 Packers and trapped pressure 7-23 permanent 6-10 production 6-8 retrievable 6-8 Perforating tubing 7-9 Permanent packers 6-10 pH 5-8 Pit gain 4-9 Plugs, bridge 6-13 Pneumatic surface safety valves 6-22 Potassium chloride 5-14 Pressure casing 3-36 dynamic analysis 2-34 friction 2-4 hydrostatic 2-8

Index

slow circulating rate 3-3 static analysis 2-16 surface 7-13 surface indicators 2-3 trapped 3-7 trapped below packers 7-23 Pressure force 2-37 Pressure gradient 2-8, 2-9 Pressure method (lubricate-and-bleed) 3-45 Preventive functions of fluids 5-3 Primary well control 3-1 Principles, friction 2-5 Production packers 6-8 Production, techniques for increasing 1-10 Pulling gas-lift dummy valve 7-6 Pulling pipe and hydrostatic pressure loss 2-30 Pulling tubing 4-7 and filling hole 4-4 and monitoring hole fill 4-4 Pulling work string 4-7 and monitoring hole fill 4-4, 4-7 Pump calculations, workover 2-28 Pump output 2-25 Pump pressure and friction 2-5 Pump unit workover 1-17

R Ram preventers installation and use 6-34 overview 6-30 Recompletion 1-7 Repair of damaged equipment 1-3 Retrievable packers 6-8 Reverse circulation method 3-19 procedures 3-20 selection guidelines 3-48 Running tubing 4-5, 4-8 Running work string 4-5, 4-8

I-5

S Safety systems, surface 6-21 Safety valves full-opening 6-35 pneumatic surface 6-22 string 6-35 subsurface-controlled subsurface 6-18 surface-controlled subsurface 6-17 Sample workover procedure 8-16 Sand production 1-4 Secondary well control 3-1 Shut-in casing pressure (SICP) 2-3 Shut-in procedures for conventional workover rig (on-bottom circulating) 3-4 for conventional workover rig (tripping) 3-5 for daylight rigs 3-6 overview 3-4 Shut-in tubing pressure (SITP) 2-3 reading with back-pressure valve 3-9 Side-pocket mandrels 6-16 Simultaneous operations 8-4 Single-salt brines 5-19 Sliding sleeves 6-17, 7-5 Slow circulating rate pressure 3-3 Sodium chloride 5-13 Solids-laden fluids 5-17 Solvent stimulation 1-10 Specific gravity 5-5 Stabilization of surface pressure 7-13 Static bottomhole pressure 2-16 Static well analysis 2-16 Steam injection 1-11 Stimulation, acid or solvent 1-10 String safety valves 6-35 Subsurface safety valves subsurface-controlled 6-18 surface-controlled 6-17 Surface indicators of pressure 2-3 Surface oil or gas 4-10 Surface pressure stabilization 7-13 I-6

Surface safety systems 6-21 Surfactant 5-10 Surging 4-4 Swabbed kick 3-49 Swabbing 4-3

T Tankage requirements, calculating 8-5 Terminology in workover procedures 8-22 Training, well control 8-6 Trapped pressure 3-7 Tree gate valves 6-26 Trip tank system 4-7 Tubing leaks 7-2 perforating 7-9 pulling 4-4, 4-7 running 4-5 Tubing capacity 2-20 Tubing hangers 6-11 Tubing plugs, wireline-set 6-38 Tubing-to-casing communication 7-4 Turbidity 5-8 Two-way check valves 6-48

U Underbalanced kick 3-50 U-tube effect 2-19

V Vacuum degasser 6-55 Viscosity 5-7 Volume method (lubricate-and-bleed) 3-43 Volumetric method 3-40

W Wait-and-weight method 3-11 procedure 3-12

Well Control for Workover Operations

Washing breaks 4-10 Water as base fluid 5-10 Water production 1-6 Waterflood injection 1-11 Weight indicator reading 4-11 Weighting material 5-10 Well control documentation 8-14 drills 8-7 overview of calculations 2-2 training 8-6 Well control equipment for concentric workover 1-15 for conventional workover 1-14 for wireline workover 1-16 for workover with pump unit 1-17 Well conversions 1-11 Well flow increase during circulation 4-9 with pumps off 4-11 Well kills during workovers 3-49 initial 3-47 Wellhead components 6-19 Well-kill methods selecting 3-47 Wireline BOPE testing 6-54 shop tests 6-54 well-site tests 6-54 Wireline workover 1-16 Wireline-cutting valves 6-25 Wireline-set tubing plugs 6-38 Work string plugged 7-22 pulling 4-4, 4-7 running 4-5 washed-out 7-22 Workover fluids components 5-9 defined 5-2 function 5-2 Index

properties 5-4 types 5-2 Workover procedure abbreviations and terminology 8-22 reviewing 8-2 reviewing with rig personnel 8-5 sample 8-16 Workovers benefits 1-12 concentric 1-15 conventional 1-14 implementation 8-11 overview of calculations 2-2 planning and preparation 8-2 reasons for 1-3 types 1-13 well control training 8-6 wireline 1-16 with pump unit (reversing unit) 1-17 Work-string check valve 7-23

I-7

I-8

Well Control for Workover Operations