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

Contents

List of Figures . . . v

List of Tables . . . ix

Preface . . . xi

1. Introduction to Workovers . . . 1-1

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

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

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

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

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

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

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

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.

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

1

I

NTRODUCTION

TO

W

ORKOVERS

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 near-wellbore 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

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:

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

• Explain the reasons for performing workovers. • Distinguish between different types of workovers.

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.

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 near-wellbore 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.

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.

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 oil-water contact zone and produce from above the oil-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.

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).

Figure 1-4 Recompletion to a higher zone

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.

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 carbonate-type 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.

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.

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

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:

• conventional workover • concentric workover • wireline workover

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

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

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

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

2

W

ELL

C

ONTROL

P

RINCIPLES

AND

C

ALCULATIONS

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:

• 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: • Wellbore and formation fluid pressures

• Wellbore fluid volumes and workover fluid volumes • Wellbore forces (acting on BOPs, plugs, packers, etc.)

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

Well & Formation Pressures Surface Indicators Calculations Surface Indicators • SITP • SICP • Friction Pressure Indicator • Hydrostatic pressure • Gradient • Equivalent fluid weight • Balanced fluid weight • Static BHP • Formation pressure • MASP Pressure Forces Well & Workover

Fluid Volumes • Tank volume • Actual pump output Calculations • Tubing and casing volumes and capacities • Annulus volumes and capacities • Displacement volumes Calculations • Cross sectional area • Pressure force • Differential force

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.”

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.

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

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.)

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.

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).

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 10,000-foot 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.

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

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.

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

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

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.

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

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

Observed Density (on hydrometer) (Observed Temp - 60) 10

---

-– = API_corrected

If observed temperature > 60°F:

If observed temperature < 60°F:

Observed Density (on hydrometer) (60 - Observed Temp) 10 --- -– = API_corrected Hydrostatic Pressure 141.5 131.5 + API_corrected ( ) ---- ×.433×TVD =

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.

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.

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

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.)

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.

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 =

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.

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

Balanced Fluid Weight (with safety margin)

Safety Margin (psi)+Formation Pressure (psi)

( ) TVD (ft) 0.052÷ ÷

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.

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 (balanced) SITP÷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

Kill Fluid Weight (Overbalanced)

(SITP+Overbalance)÷TVD_perfs÷0.052

[ ]

Tubing Fluid Weight

+

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.

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:

• The principle of additive pressures

• Why the casing pressure differs from the tubing pressure • The U-tube effect

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

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

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

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:

• tubing and casing capacities • annular capacities

• displacement volume • fluid tank volumes • pump output

• hydrostatic pressure loss when pulling pipe • dynamic pressure 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.)

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.

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.

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

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).

Figure 2-8 Determining annular capacity factor and annular volume

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

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.

Figure 2-9 Determining displacement factor and displacement volumes 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

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.

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

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

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

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).

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

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.

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 =

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.

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