60755868 work over well control

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While every effort was made to ensure accuracy, this manual is intended only as a training aid. Nothing in it should be

assumes no liability with respect to the use of any information, apparatus, method, or process in this manual. This manual was developed by
Schlumberger


Types of Workovers and Associated Well Control Equipment . . . . . . . . . 1-13

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

Shut-in Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4


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

Surface Safety Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-21

Trapped Pressure below Packers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-23
Use of Work-String Check Valve. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-23
8/20/2019 60755868 Work Over Well Control

A. Abbreviations for Chemical Compounds . . . . . . . . . . . . . . . . . . . . . . . . A-1B. Summary of Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
C. Increasing Density in Multiple-Salt Brines . . . . . . . . . . . . . . . . . . . . . . . A-8
D. Conversion Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-10
F. IPM Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-14


W e l l C o n t r o l f o r W o r k o v e r O p e r a t i o n s
1-3. Water coning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7
1-6. Zonal isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9
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 . . . . . . . . . 2-32-2. 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 . . . . . . . . . . . . . . . 2-382-13. 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

3-15. 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
3-24. 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
6-3. 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
6-12. Bridge plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-13
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
6-23. 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

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



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

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

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:


Although there are various reasons for workovers, most can be grouped into six
basic categories:
• Repair natural damage within the well
• Recomplete to another zone
• Replace artificial-lift 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:
• Electric submersible pumps (ESPs) and rod pumps
For detailed descriptions of equipment, see Lesson 6, “Surface and Subsurface
Equipment.”

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.

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.

In certain reservoirs, the gas associated with the oil serves as a major driving energy

. 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

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.

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 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.

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).


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

(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
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

.
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.
1-12 W e l l C o n t r o l f o r W o r k o v e r O p e r a t i o n s
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.
L e s s o n 1 1-13
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).
Types of Workovers and Associated Well Control Equipment
This section lists key points and equipment configurations for four basic types of
workovers:
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
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).
• Stripper or annular
Wireline Workover
Key Points
2 Wireline is used instead of work string.
3 Well may or may not have pressure.
4 Lubricator is installed.
Workover with Pump Unit (Reversing Unit)
Key Points
2 Well generally has pressure.
3 Existing tubing is used as work string.
4 Workover unit is used primarily to kill producing wells.
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:
• Correctly interpret surface indicator data.
• 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 & FormationPressures
Surface Indicators
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.
Fig. 2-3 illustrates some examples of these principles.
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
L e s s o n 2 2-7
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.
Figure 2-4 True vertical depth (TVD) and measured depth (MD)
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
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:
Find: Pressure gradient of the fluid
Solution: Pressure Gradient = 9.6 × 0.052 = 0.499 psi/ft
Example 2:
Find: Fluid weight (density)
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
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 ------------------------------- – APIcorrected =
Observed Density (on hydrometer) (60 - Observed Temp)
10 ------------------------------- – APIcorrected =
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 bemathematically precise, it’s a good idea to be familiar with them so you can better
communicate with others.
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
Solution: Equivalent FW = 2,600 ÷ 9,854 ÷ 0.052 = 5.07 = 5.1 ppg
Example 2:
Solution: Equivalent FW = 0.530 ÷ 0.052 = 10.19 = 10.2 ppg
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 ina 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
Solution: Balanced FW = 9,800 ÷ 14,300 ÷ 0.052 = 13.179 ppg =
13.2 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:
Solution: Kill FW = (1,900 ÷10,570 ÷ 0.052)
+ 6.7 = 10.16 ppg = 10.2 ppg*
Example 2:
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 TVDperfs÷ 0.052÷( )
Tubing Fluid Weight+
psi overbalance
Kill Fluid Weight (Overbalanced)
(SITP Overbalance) TVDperfs 0.052÷÷+[ ]
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:
• Why the casing pressure differs from the tubing pressure
• The U-tube effect
Total Tubing Hydrostatic Pressure
Example:
Given: SITP = 1,900 psi, tubing fluid weight = 6.7 ppg, TVD = 10,670 ft
(see Fig. 2-5)
Solution: BHP = 1,900 + (6.7 × 0.052 × 10,670) = 5,617 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
Static Well Analysis
Find: Static BHP
(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
L e s s o n 2 2-19
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:
• 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) =
(bbls/ft) × Length (ft)
4.7 pounds per foot (ppf)
Find: Internal volume in bbls
Solution:
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
inside 5-1/2"; 17 ppf casing Find: Annular volume in bbls
Solution: Annular Capacity Factor =
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.
Displacement Calculations
Displacement Volume (bbls) = Displacement
Factor (bbls/ft) × Length (ft)
Closed-end Displacement Factor (bbls/ft) =
OD (inches) 2 ÷ 1029.4
Find: Steel displacement volume in bbls
Displacement Factor = 4.7 ÷ 2750* =
Find: Closed-end displacement in bbls
Displacement Factor = 2.3752 ÷ 1029.4 =
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.
L e s s o n 2 2-25
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'
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
Solution: Pump Output = 5 ÷ 71 = 0.070 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 =
43 spm
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.).
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
Solution: Actual Pump Rate = 9.5 bbl ÷ 5.0 min = 1.9 bpm
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"
Find: Tank calibration (bbls/in), bbls required, actual pump output, total
strokes, required pump speed, and total minutes
Solution:
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 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
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.
L e s s o n 2 2-31
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.
Fluid Level Drop (ft) Displacement Factor Length Pulled ×
Annular Capacity Factor Tubing Capacity Factor +( ) ----------------------------------------------------------------------=
×=
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:
4.892 2
2.875 2
Tubing wt/ft 2750÷( ) Length Pulled ×
Casing ID 2
Tubing OD 2
Hydrostatic Pressure Loss (Wet Pipe)
Fluid Level Drop (ft) =
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:
* 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.
Displacement Factor Capacity Factor +( ) Length Pulled ×
(Annular Capacity Factor) -----------------------------------------------------------------------------
1029.4÷( )+( ) Length Pulled ×
Casing ID 2
Tubing OD 2
Fluid Level Drop 6.5 2750÷( ) 2.441
2 1029.4÷( )+( ) 1,000×
L e s s o n 2 2-33
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 =
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.
Allowable Pressure Loss (psi) Tubing Capy. Factor Ann. Capy. Factor +( )×
0.052 Fluid Weight (ppg)× ------------------------------------------------------------------------------------------------------
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.
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.
Given: Tubing friction = 2,400 psi; annulus friction = 300 psi;

60755868 work over well control

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