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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
13/322
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.
http://slidepdf.com/reader/full/60755868-work-over-well-control
14/322
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
15/322
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
16/322
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.
http://slidepdf.com/reader/full/60755868-work-over-well-control
18/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
19/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
20/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
21/322
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).
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
22/322
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
23/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
24/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
25/322
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.
http://slidepdf.com/reader/full/60755868-work-over-well-control
26/322
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.
http://slidepdf.com/reader/full/60755868-work-over-well-control
27/322
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:
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
28/322
1-14 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
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
29/322
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
30/322
1-16 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
Wireline Workover
Key Points
2 Wireline is used instead of work string.
3 Well may or may not have pressure.
4 Lubricator is installed.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
31/322
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.
Well Control Equipment
http://slidepdf.com/reader/full/60755868-work-over-well-control
32/322
1-18 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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
33/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
34/322
2-2 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
• 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.)
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
35/322
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
36/322
2-4 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
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.”
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
37/322
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
38/322
2-6 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
39/322
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.)
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
40/322
2-8 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
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)
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
41/322
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
42/322
2-10 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
43/322
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 =
http://slidepdf.com/reader/full/60755868-work-over-well-control
44/322
2-12 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
45/322
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
46/322
2-14 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
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÷÷=
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
47/322
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÷÷+[ ]
http://slidepdf.com/reader/full/60755868-work-over-well-control
48/322
2-16 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
49/322
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
50/322
2-18 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
51/322
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
52/322
2-20 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
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:
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
53/322
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 =
http://slidepdf.com/reader/full/60755868-work-over-well-control
54/322
2-22 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
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
55/322
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 =
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
56/322
2-24 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
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
57/322
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
58/322
2-26 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
59/322
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
60/322
2-28 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
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
61/322
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
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
62/322
2-30 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
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
63/322
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
http://slidepdf.com/reader/full/60755868-work-over-well-control
64/322
2-32 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
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×
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
65/322
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)×
------------------------------------------------------------------------------------------------------
http://slidepdf.com/reader/full/60755868-work-over-well-control
66/322
2-34 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
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.
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
67/322
8/20/2019 60755868 Work Over Well Control
http://slidepdf.com/reader/full/60755868-work-over-well-control
68/322
2-36 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
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;