Control principles and procedures

Control Principles and
Procedures

INTRODUCTION
PROCEDURES FOR MAINTAINING CONTROL
of an oil or gas well during workover and
completion differ significantly from drilling well
control procedures. Although the basic pressure
principles remain the same, the manners of
implementation vary so greatly that they give
the appearance of being a different subject. As
a result, it becomes necessary to study several
different well control procedures depending on
formation pressures and operating conditions.

INTRODUCTION
Formation pressure is defined as the pressure
of the fluid within the pore spaces of the rock.
Normal pressure is considered to be equal to
the hydrostatic pressure of a full column of
native water from the surface to the vertical
depth of interest. Abnormal pressures are those
not equal and generally greater than normal.
Subnormal pressures are a special case of
abnormal pressures and are less than normal.
Routine operating conditions necessitate
different well control procedures.

INTRODUCTION
The most common situations are killing a
producing well and controlling kicks that occur
during the workover. Further conditions that
dictate well control procedures are type of
completion, formation pressure(s) exposed to
the wellbore, and the reasons for implementing
a workover operation. Many factors must be
known before selecting the proper kill
procedure.

CONTENTS
 Causes of Kicks
 Warning Signs of Kicks
 Shut-in Procedures
 Responsibilities for Shut-in
 Obtaining and Interpreting Pressures
 Guidelines to Check for Trapped Pressure
 Kill Weight Mud Calculations
 Killing a Producing Well
 Kill During Workover

Causes of Kicks
A kick is an undesirable entry of formation fluids
into casing or tubing.
Kicks occur as a result of formation pressures
exceeding workover fluid hydrostatic pressures
and causing formation fluids (gas, oil, or saltwater)
to flow into the wellbore. In almost all workover
operations, the operator attempts to maintain a
hydrostatic pressure slightly greater than the
formation pressure and thus prevent kicks. On
occasion, however, and for various reasons, the
formation pressure will exceed the mud pressure
and a kick will occur.

Causes of Kicks
Insufficient Mud Weight
Improper Hole Fill-Up
Swabbing
Cut Mud

Causes of Kicks
-- Insufficient Mud Weight
Insufficient mud weight is one of the predominant
causes of kicks. In this case, a permeable zone is
exposed while using a mud weight that exerts less
pressure than the formation pressure. As a result of
this pressure imbalance, fluids begin to flow into the
wellbore and the kick occurs.

A common source for this type of kick during
workovers is drilling through obstructions such as
sand bridges or junk in the tubing or casing. Pressures
may be found below the bridge that are greater than
the hydrostatic pressure of the fluid above the bridge.
This situation may become difficult to control since
"endswapping" of the fluids may occur. This will
increase the difficulty of circulating the kick until the
swapping is completed.
Causes of Kicks
-- Insufficient Mud Weight

Filling the hole improperly during trips is another
dominant cause of kicks. As the work string is
pulled out of the hole, the mud level falls because
the work string steel has displaced some amount
of mud. With the pipe no longer in the hole, the
mud must fall. The overall level will decrease and,
as a consequence, the hydrostatic pressure of the
mud will also decrease.
The following example illustrates the hydrostatic
reduction when the drill pipe is pulled from the
well.
Causes of Kicks
-- Improper Hole Fill-Up

Example 4.1: Calculate the hydrostatic pressure
reduction when pulling 10, 93-ft stands of drill pipe
without filling the hole.
Hole data:
Casing ID—5.0 in.
Work string—2 7/8 in., 8.35 Ib/ft
Capacity and displacement data:
Work string capacity—0.005242 bbl/ft
Annular capacity (2 7/8 x 5.0-in.)—0.01615 bbl/ft
Work string displacement—0.0032 bbl/ft
Mud weight—9.8 ppg
Causes of Kicks

Solution:
(1) What is the total fluid displaced by 10 stands of
pipe?
10 stands x 93 ft/stand x 0.0032 bbl/ft = 2.976 bbl
(2) How many feet does 2.976 bbl fill?
Annulus plus work string capacity = 0.01615 +
0.005242 = 0.0213 bbl/ft
2.976 bbl/ (0.0213 bbl/ft) = 139.7 ft
(3) What pressure reduction would occur?
0.052 x 9.8 ppg x 139.7 ft = 71.2 psi
Causes of Kicks

It should be obvious from this example that it is necessary
to fill the hole with mud periodically to avoid sufficiently
reducing the hydrostatic pressure and allowing a kick to
occur. Several methods can be utilized to fill the hole, but
all must be able to measure the amount of mud required
accurately. It is not satisfactory under any conditions to
allow a centrifugal pump to fill the hole continuously ; from
the suction pit since accurate mud volume measurement is
not possible. The two methods most commonly used to
monitor hole filiup are a trip tank and pump stroke
measurement.
Causes of Kicks

A trip tank is any small tank with a calibration
device that can be used to monitor the volume of
mud entering the hole. The tank can be placed at
some level equal to the preventer height in order
to allow a gravity feed into the annulus, or a
centrifugal pump could transfer mud to the
annulus with the overflow returning to the trip tank.
The primary advantages of the trip tank are that
the hole remains full at all times and an accurate
measurement of the mud entering the hole is
possible.
Causes of Kicks

Another method of keeping the hole full of mud is
periodically to fill the hole with a positive
displacement pump such as the main rig pump. A
flow line device can be installed that will measure
the pump strokes required to fill the hole and will
automatically shut off the pump when the hole
becomes full. The following example illustrates the
usage of the rig pump to fill the hole during a trip.
Causes of Kicks

Example 4.2: Calculate the number of pump strokes required
to fill the hole if 10 stands of pipe are pulled from the hole.
Use the data from Example 4.1.
Data
Pump — Single-acting triplex
— 3-in. liner, 6-in. stroke •
Output — 0.0131 bbl/stroke
Solution:
(1) From Example 4.1, 10 stands of pipe displace 2.976
barrels.
(2) How many strokes will be required?
Barrels — barrels per stroke =2.976 bbl/(0.0131 bbl/stroke)
= 111 strokes (per 10 stands)
Causes of Kicks

Causes of Kicks -- Swabbing
Swab pressures are created by pulling the work
string from the borehole. The swab pressure is a
negative pressure and reduces the effective
hydrostatic pressure throughout the hole. If this
pressure reduction is large enough to lower the
effective hydrostatic pressure to a value below the
formation pressure, a potential kick situation has
developed.

Among the variables controlling swab pressures are
pipe pulling speed, mud' properties, hole configuration,
and the effect of large workover tools such as squeeze
tools and packers. Pulling speed is the primary
variable that can be controlled during the tripping
process. In order to reduce the swab pressure, pulling
speed must be reduced.

It is important to remember that the swab
pressure is added to the pressure reduction
resulting from not keeping the hole full as the
pipe is pulled. In addition, the swab pressure is
exerted at every point throughout the open hole
below the work string even though the drill
string may be inside the casing.

Causes of Kicks -- Cut Mud
Gas contamination will occasionally cause a kick
although the occurrence is rare. The mud density
reduction is usually caused by formation fluids such as
gas entering the wellbore. As the gas is circulated to
the surface, it may expand and reduce the overall
hydrostatic pressure to a point sufficient to allow a kick
to occur. Although the mud weight is cut severely at
the surface, the total hydrostatic pressure is not
reduced significantly since most of the gas expansion
occurs near the surface and not at the bottom of the
well.

Warning Signs of Kicks
A number of warning signs and possible warning
signs of kicks can be observed at the surface. It is
the responsibility of each crew member to
recognize and interpret these signs and to take the
proper actions with respect to his well control
duties. Although all of the signs do not positively
identify a kick, they do I warn of a potential kick
situation. Each warning sign is identified here as
either | primary or secondary relative to its
importance in kick detection.

Flow Rate Increase
Flowing Well With Pumps Off
Pressure Decrease and Stroke Increase
Improper Hole Fillup
String Weight Change
Cut Mud Weight

-- Flow Rate Increase
An increase in the flow rate, leaving the well
while pumping at a constant rate, is one of the
primary kick indicators. The increased flow rate
is interpreted to mean that the formation is
aiding the rig pumps in moving the fluid up the
annulus by forcing fluids into the wellbore.
(Primary indicator)

-- Flowing Well With Pumps Off
When the rig pumps are not moving the mud, a
continued flow from the well indicates that a kick
is in progress. An exception to this occurs when
the mud in the drill pipe is considerably heavier
than that in the annulus, as in the case of a slug.
(Primary indicator)

-- Pressure Decrease and Stroke Increase
A pump pressure change may indicate a kick. The initial
entry of the kick fluids into the borehole may cause the
mud to flocculate and temporarily increase the pump
pressure. As the flow continues, the low-density influx
will displace the heavier workover fluids and the pump
pressure may begin to decrease. As the fluid in the
annulus becomes less dense, the mud in the work string
may tend to fall and the pump speed may increase.
(Secondary indicator)

-- Pressure Decrease and Stroke Increase
Many other problems may exhibit these same
signs. A hole in the pipe, called a washout, will
cause the pump pressure to decrease, and a
twist-off of some portion of the drill string will
show the same signs. It is the proper procedure,
however, to check for a kick if these signs are
observed.

-- Improper Hole Fillup
When the work string is pulled out of the well, the mud
level should decrease by a volume equivalent to the
amount of steel removed. If the hole does not required
the calculated volume of mud to bring, the mud level
back to the surface, it is assumed that a kick fluid has
entered the hole and replaced the volume of the missing
work string. Even though gas or saltwater has entered
the hole, the well may not flow until enough fluid has
entered to reduce the hydrostatic pressure to an amount
less than the formation pressure. (Primary indicator)

-- String Weight Change
The drilling fluid in the hole provides a buoyant effect to
the work string and effectively reduces the actual pipe
weight that must be supported by the derrick. Heavier
muds have a larger buoyant force than less-dense muds.
When a kick occurs and low density formation fluids
begin to enter the borehole, the total buoyant force of the
mud system is reduced. As a result, the string weight
observed at the surface begins to increase. (Secondary
indicator)

-- Cut Mud Weight
Reduced mud weight observed at the flow line has
occasionally caused a kick to occur. Some of the causes
for the reduced mud weight are core volume cutting,
connection air, or aerated mud that was circulated from
the pits and down the work string. Fortunately, the lower
mud weight due to the cuttings effect is found very near
the surface, generally due to gas expansion, and does
not cut the density of the mud appreciably downhole.
Gas cutting can have a very small effect on the
bottomhole hydrostatic pressure.

-- Cut Mud Weight
An important point to remember about gas
cutting is that if the well does not kick as the gas
is circulated to the surface, there is only a small
possibility that it will kick. Generally, gas cutting
only indicates that a slug of gas has been
penetrated such as trapped gas below a bridge.
It does not necessarily mean that the mud
weight must be increased. (Secondary indicator)

Shut-in Procedures
When one or more of the warning signs of kicks
are observed, steps should be taken to shut-in the
well. If there is any doubt as to whether the well is
flowing, shut it in and check the pressures. Also,
there is no difference between a small flow and a
full-flowing well because both can very quickly
turn into a ' 'big'' blowout.

Shut-in Procedures
Some hesitation has been expressed by industry
personnel about fracturing the well through the
perforations into adjacent formations and possibly
creating an underground blowout as a result of
shutting in the well when a kick occurs. If the well
is allowed to flow, it will eventually become
necessary to shut-in the well, at which time the
possibility of fracturing the well will be greater
than had the well been shut-in immediately after
the initial kick detection.

Shut-in Procedures
There has been considerable discussion as
to the merits of the hard shut-in versus the
soft shut-in procedure. A hard shut-in is one
in which the annular preventer(s) are closed
immediately after the pumps are shut down.
During the soft shut-in procedures, the
choke is opened prior to closing the
preventer, and then the choke is closed.

Shut-in Procedures
The two primary arguments in favor of soft shut-in
procedures are to avoid a water-hammer effect
due to stopping fluid flow abruptly and to provide
an alternate means of well control (low choke
pressure method) should the casing pressure
become ' 'excessive". The water hammer effect
has no proven substance. In addition, the low
choke pressure method has been shown to be an
unreliable procedure. The primary argument
against the soft shut-in procedures is that of a
continuous influx while the procedures are
executed.

Shut-in Procedures
For these reasons, only the hard shut-in
procedure will be presented in this manual.
Several types of hard shut-in procedures are
applicable for well control depending upon
the type of rig in use and the activity
occurring when the kick is taken. Variations
of shut-in procedures are:
Drilling or working-immobile rig
Tripping—immobile rig
Drilling or working-floating rig
Tripping—floating rig

Shut-in Procedures
-- Drilling or Working - Immobile Rig
Some hesitation has been expressed by industry
personnel about fracturing the well through the
perforations into adjacent formations and possibly
creating an underground blowout as a result of
shutting in the well when a kick occurs. If the well
is allowed to flow, it will eventually become
necessary to shut-in the well, at which time the
possibility of fracturing the well will be greater
than had the well been shut-in immediately after
the initial kick detection.

Shut-in Procedures
An immobile rig does not move during
normal drilling operations. Some types are
land and barge rigs, jack-ups, and platform
rigs.

Shut-in Procedures
Shut-in procedures:
1. When a primary warning sign of a kick has
been observed, immediately raise the kelly until
a tool joint is above the rotary table.
2. Stop the mud pumps.
3. Close the annular preventer.
4. Notify the company personnel.
5. Read and record the shut-in tubing pressure,
the shut-in casing pressure, and the pit gain.

Shut-in Procedures
Raising the kelly is an important procedure
for several reasons. With the kelly out of
hole, the valve at the bottom of the kelly can
be closed if necessary. In addition, the
annular preventer members can attain a
more secure seal on pipe than on a kelly.

Shut-in Procedures
-- Tripping - immobile rig
A high percentage of well control problems
occur when a trip is being made. The kick
problems may be compounded when the
rig crew is preoccupied with the trip
mechanics and they fail to see the initial
warning signs of the kick.

Shut-in Procedures
Shut-in procedures:
1. When a primary warning sign of a kick has been
observed, immediately set the top tool joint on the
slips.
2. Install and make up a full-opening, fully opened safety
valve in the work
3. Close the safety valve and the annular preventer.
5. Pick up and make up the kelly.
6. Open the safety valve.
7. Read and record the shut-in tubing pressure, the shut-
in casing pressure, andthe pit gain.

Shut-in Procedures
Installing a full-opening safety valve instead of an inside
blowout preventer (float) valve is a prime consideration
because of the advantages offered by the full-opening
valve. If flow is encountered up the work string as a result
of a trip kick, the fully opened, full-opening valve is
physically easier to stab on the pipe than a float-type
inside blowout preventer valve which would automatically
close when the upward-moving fluid contacts the valve.
(Assume that a manual lock float valve is not in use.)

Shut-in Procedures
If wireline work such as perforating or logging
becomes necessary, the full opening valve will
accept logging tools approximately equal to its
inner diameter. The float valve may prohibit
wireline work altogether. After the kick is shut-in,
an inside blowout preventer float valve may be
stabbed on top of the full opening valve to allow
stripping operations for the return to bottom.

Shut-in Procedures
-- Drilling or working-floating rig
A floating rig is one that moves during t normal
drilling operations. The primary types of floating
vessels are semisubmersibles and drill ships.
There are several differences in the shut-in
procedures for floaters due to their tendency to
promote work string movement even with a
motion compensator in operation and also due to
the placement of the blowout preventer stack on
the sea floor. To solve the problem of possible
vessel and work string movement and the
resultant wear on the preventers, a tool joint will
be lowered on the closed pipe rams and the string
weight hung on these rams.

Shut-in Procedures
One problem with a stack located a
considerable distance from the rig floor is to
ensure that a tool joint does not interfere
with the closing of the preventer elements.
To avoid this problem, a spacing-out
procedure should be executed prior to
taking a kick by closing the rams, slowly
lowering the drill string until a tool joint
contacts the rams, and recording the
position of the kelly at that point.

Shut-in Procedures
Shut-in procedures:
1. When a primary warning sign of a kick has been
observed, immediately raise the kelly to the level
previously designated during the spacing out procedure.
2. Stop the mud pumps.
3. Close the annular preventer.
5. Close the upper set of pipe rams.
6. Reduce the hydraulic pressure on the annular preventer.
7. Lower the drill pipe until the pipe is supported entirely
by the rams.
8. Read and record the shut-in tubing pressure, shut-in
casing pressure, and the pit gain.

Shut-in Procedures
-- Tripping—floating rig
The procedures for kick closure during tripping on a
floater are a combination of the floating drilling
procedures and the immobile rig tripping procedures.
Shut-in procedures:
1. When a primary warning sign of a kick has been observed,
immediately set the top tool joint on the slips.
2. Install and make up a full-opening, fully opened safety valve
in the work string.
3. Close the safety valve and the annular preventer.
5. Pick up and make up the kelly.
6. Close the upper set of pipe rams.
7. Reduce the hydraulic pressure on the annular preventer.
8. Lower the work string until the pipe is supported by the rams.
9. Read and record the shut-in tubing pressure, shut-in casing
pressure, and the pit gain.

Responsibilities for Shut-in
Each member of the crew has different responsibilities during
the various shut-in procedures.
Floorhand (Roughneck)
1. Notify the driller if any warning signs of kicks are observed.
2. Assist in installing the full-opening safety valve if a trip is being made.
3. Initiate his well control responsibilities after the well is shut-in.
Derrickman
1. Notify the driller if any warning signs of kicks are observed.
2. Initiate the well control responsibilities and begin mud mixing
preparations.
Driller
1. Shut-in the well immediately if any of the primary warning signs of kicks
are observed.
2. If a kick occurs while making a trip, set the top tool joint on the slips and
direct the crews in the installation of the safety valve prior to closing the
preventer.
3. Notify all proper company personnel.

Logic for Kill Procedures
Several variables control kill procedures
for workover operations. These are the
well's present flowing status (it may
require killing before reentry can be made),
the magnitude of the formation pressures
that must be controlled, and special
considerations such as formation fracture
pressure or casing burst.

In addition, certain unknown variables
such as tubing holes, packer leaks, and
sand bridges must be evaluated with
respect to the complications they create
on an already difficult problem. After all
known and unknown variables are studied,
the kill procedure can be developed for the
given situation.

Normal Formation Pressure
A normal formation pressure is equal to the hydrostatic
pressure of a full column of native water. As a result,
most formations can be controlled with a mud system
(freshwater, saltwater, gel mud, etc.) weighing from
8.33-9.0 ppg. The basic logic to kill a normal pressure
well, therefore, is to stand a column of the required
density fluid from the surface to the flowing zone.
Attaining a full column of water (mud) may be done by
lubricating, bullheading, or by circulating. Individual
well characteristics will determine the most feasible
procedure to use.

Subnormal Formation Pressure
Routine production operations generally reduce
the pressure within the formation to values less
than normal. When this situation occurs, kill
fluid densities may fall below 8.33-9.0 ppg.
These subnormal formation pressures require
special considerations relative to well control.

A problem inherent while reworking subnormal pressure zones
with clear water (fresh or saltwater) is the loss of water to the
interval if any pressure overbalance is maintained. The slight
pressure overbalance, which is normally used to prevent kicks,
will force clear workover fluids to enter the permeable
producing interval in an effort to create a balance. As a result,
any swabbing action by the work string will cause the well to
flow and a kick to occur. This problem is not restricted to
subnormal zones but is often encountered with normal pressure
intervals.

Several solutions are available to remedy the problem
of fluid loss to an open zone. The most feasible is to
plug the zone with a material such as calcium
carbonate or polymer that can be removed later (Fig.
4.1). Several packaged products are available from
commercial suppliers for this purpose. After the
workover is completed, the bridging material can be
removed with acid or a chemical breaker.

Another technique used to isolate low pressure
intervals is placement of a mechanical bridge such as
a packer. The packer is placed in the well above the
open zone so that the workover operations can be
completed. This procedure is feasible only if the
workover is designed to alleviate some problem above
the productive interval and not the interval itself. After
the work is completed, the packer is removed and the
well is again put on production.

A popular misconception about workovers and
completion of subnormal pressure zones is that they
pose no well control problems since the productive
interval has low pressures. In fact, most blowouts
occur in normal or subnormal; pressure zones and not
in abnormally high pressure wells. It is important,
therefore, to be as cautious with low formation
pressures as with any other interval.

Abnormal (High) Pressures
Maintaining control of a well with abnormal
formation pressures requires additional
planning. Items to consider are an evaluation of
shut-in pressures, kill density fluid requirements,
and burst pressures of the casing and tubing. In
addition, completion techniques such as
tubingless completions employed with high-
pressure zones further complicate the process.

Obtaining and Interpreting Pressures
The shut-in pressures are recorded on the work
string and casing during a closed-in condition.
Although both pressures are important, the
work string pressure will be used almost
exclusively in killing the well. Shut-in tubing
(work string) pressure is labeled SITP and shut-
in casing pressure is abbreviated SICP. For the
equations which follow, assume that the tubing
or work string does not contain a float.

An important basic principle can be seen in Fig.
4.2. In this case, the formation pressure (BHP)
is greater than the tubing hydrostatic pressure
by an amount equal to the SITP. This can be
expressed as in Equation:
SITP + Tubing hydrostatic pressure =
Bottomhole formation pressure
Likewise, the casing pressure can be used to
evaluate BHP.
SICP + Annular mud + Annular influx =
Bottomhole formation

It is usually difficult to determine the annular influx
hydrostatic pressure in practical situations. Therefore,
Eq. 4.2 is not field applicable. Fig. 4.2 can illustrate
another important basic principle. It was shown that
the pressure on the tubing gauge was the amount
necessary to balance the tubing hydrostatic pressure
with the pressure of the gas in the sand at 12,000 ft.
The laws of physics say that fluids travel from areas of
high pressure to areas of lower pressure and do not
travel between areas of equal pressures.

Therefore, if the tubing pressure is controlled in
such a manner that the total pressure at the
hole bottom is slightly greater than the
formation fluid pressure, no additional kick
influx will enter the well. The concept is the
basis of the constant bottomhole pressure
method of well control in which the pressure at
the bottom of the hole is maintained constant
and at least equal to the formation pressure.

Trapped pressure can cause errors in interpreting the
shut-in pressures. This type of pressure is defined as
any pressure recorded on the tubing or casing that is
more than the amount needed to balance the
bottomhole pressure. Pressure can be trapped in the
system in several ways, but the most common are gas
migrating up the annulus and tending to expand, or
closing the well in before the mud pumps have quit
running. If a pressure reading contains some amount
of trapped pressure the calculations to kill the well will
be in error.

Guidelines to Check for Trapped Pressure
When checking for trapped pressure, bleed
from the casing side onlv The primary choke is
generally located on the casings, This avoids
contamination of the mud (or brine water) in the
work string ( tubing) and the possibility of
plugging the jets of the bit, circulating port, or
sliding sleeve.
Use the work string pressure as a guide since it
is a direct bottomhole pressure indicator.
Bleed small amounts (1/4 to 1/2) bbl of mud at
a time. Close the choke after bleeding and
observe the pressure on the work string.

Continue to alternate the bleeding and
subsequent pressure observation procedures
as long as the shut-in work string pressure
continues to decrease. When the pressure
ceases to fall, stop bleeding and record the true
SITP and SICP.
If the SITP should decrease to zero during this
procedure, continue to bleed and check
pressures on the casing side as long as the
casing pressure decreases. (Note: This step will
normally not be necessary.)

The basis for the procedure listed above is that
trapped pressure is more than the amount
needed to balance the bottomhole pressure and
it can be bled off without allowing any additional
influx into the well. However, after all of the
trapped pressure is bled off and if the bleeding
procedure is continued, more influx will be
allowed into the well and the surface pressures
will begin to increase.

These bleeding procedures can be implemented
at any time. However, it is advisable to check
for trapped pressure when the well is shut-in
initially and to recheck when the work string is
displaced with a clean kill fluid if any pressure
remains on the work string.

Occasionally, kick killing procedures must be
implemented when a tubing float valve is used.
Since a float valve prevents fluid and pressure
movement up the work string, there will be no
pressure readings after the well is shut-in.
Several procedures for determining the tubing
pressure (SITP) are available. Each depends
on the amount of information known at the time
that the kick occurs.

Find SITP if Kill Rate is Known
1. Shut-in the well, record the shut-in casing pressure (SICP) and
obtain the kill rate either from the driller or the daily tour report.
2. Instruct the driller to start the pumps and maintain the pumping
rate at the kill rate (strokes).
3. As the driller starts the pumps, use the choke to regulate the
casing pressure at the same pressure that was originally
recorded at the shut-in conditions.
4. After the pumps are running at the kill rate with the casing
pressure properly regulated at the shut-in pressure, record the
pressure observed on the tubing while pumping.
5. Shut down the pumps and close the choke.
6. The shut-in tubing pressure equals the total pumping pressure
minus the kill rate pressure, or SITP = Total Pressure - kill rate
pressure

Find SITP if Kill Rate is Not Known
1. Shut-in the well.
2. Line up a low-volume, high-pressure reciprocating
pump on the stand
3. Start pumping and fill up all of the lines.
4. Gradually increase the torque on the pumps until
the pumps initially begin to move fluid down the
work string.
5. The SITP is the amount of pressure required to
initiate fluid movement, This is assumed to be the
amount needed to overcome the pressure acting
against the bottom side of the valve.

Kill Weight Mud Calculations
Subsequent to the determination of the shut-in
pressures, calculations must be made to define
a fluid density that will create a hydrostatic
pressure equal to or greater than formation
pressure. Kill weight mud (or brine water) is
defined as the fluid density necessary to
balance bottomhole formation pressure exactly.
It will provide the required controlling pressures
yet minimize the possibility of casing burst or
formation fracture.

Calculating required kill mud densities uses an equation
similar to that shown in Eq.:
KWM = (SITP + THP) x 19.23/Depth
Where:
KWM = Kill weight mud, ppg
SITP = Shut-in tubing pressure, psi
Depth = True vertical depth, ft
19.23 = Conversion constant, ppg/psi/ft
THP = Tubing hydrostatic pressure, psi
KWM == BHP x 19.23/depth
Where:
BHP = Bottomhole pressure, psi

Equations is the most direct method if the
bottomhole pressure is known. As can be seen
in Eq., an indirect calculation of bottomhole
pressure is made before KWM is determined.
Difficulties may arise when using Eq. if THP
must be calculated when various density fluids
exist in the tubing. Examples 4.3 and 4.4
illustrate the calculation procedures for KWM
determinations.

Example 4.3
A well is producing under the following
conditions. If a workover becomes necessary,
what kill weight fluid is required?
Data:
Perforations at 10,250 ft (TVD)
BHP = 4,745 psi
Solution:
KWM = BHP x 19.23/Depth
= 4745 psi x 19.23/10,250 ft
= 8.9 ppg

Example 4.4
Calculate a kill fluid density for workover under the following
conditions.
Data:
SITP = 3,950 psi
Specific Gravity =0.69 (oil in tubing)
Solution:
(1) Calculate THP
THP = 0.052 x 8.33 ppg x 0.69 x 11,600 ft
= 3,467 psi
(2) Use Equation 4.4
KWM = (SITP + THP) x 19.23/Depth
= (3,950 psi + 3,467 psi) x 19.23/11,600 ft
= (7,417 psi) x 19.23/11,600 ft
= 12.29 ppg

Formation Fracture Pressures
The basic logic for most well control situations is
to circulate a full column of kill density fluid. As
previously discussed, this technique can be
complicated if a permeable formation is
exposed. It will allow fluid flow into the fomation
if an overbalance occurs. Further complications
can arise if an undesirable formation fracture is
created that will allow a loss of workover fluids
into adjacent formations.

This usually occurs when the fracture pressure
of the formation has been exceeded. Formation
fracture pressures depend on depth, rock type,
and formation pressure. Several authors have
studied these variables and have shown that
shale sections will generally fracture with
pressures less than those required for sand
sections. Although most completion practices
will attempt to isolate the producing interval
from other zones, it should be assumed that a
small section of shale is exposed.

As a result, the formation fracture pressure (or
gradient) must be calculated using shale as the
rock type. This conservative approach yields a
minimum value for possible fracture pressures.
Calculation procedures for the determination of
fracture pressure (termed fracture gradient
when expressed in psi/ft) generally involve
complex equations and graphs. However, a
chart such as Fig. 4.3 resolves these
complexities into a simple, direct solution.
Example 4.5 illustrates use of the chart.

Example 4.5
A workover is to be performed on a well with the
characteristics described below. What would be
the minimum fracture pressure under the given
conditions? In addition, what static tubing
pressure would fracture the formation?
Data:
Formation pressure = Normal
Produced fluid in tubing =0.7 specific gravity oil

Solution:
(1) Using the Eaton chart, enter on the vertical scale at
a depth of 8,600ft. Read on a horizontal line until the
normal pressure (9.0 ppg) formation line is
encountered. From this intersection, read vertically
until the fracture pressure of 16.2 ppg is read.
(2) The fracture pressure in terms of psi is:
0.052 x 16.2 ppg x 8,600 ft = 7,244 psi
SITP = Fracture pressure - oil hydrostatic pressure
= 7,244 psi - (0.052 x 0.7 x 8.33 ppg x 8,600 ft)
= 7,244 - 2,607
= 4,637 psi

Killing a Producing Well
The first step in workover operations often
involves killing a well that is producing
hydrocarbons. Numerous kill procedures are
available depending on circumstances such as
tubing and casing integrity, ability to circulate the
fluid in the annulus, formation pressure, and
characteristics of the completion methods and
formation parameters that may control techniques
such as reverse pumping into the formation.
Individual wells must be evaluated to determine
the most effective procedure.

Entering the Well
Killing a Normal-Pressure Well
Annulus Kill Procedures
Kill with a Hole in the Tubing
Tubing Kill Procedures
Abnormal-Pressure Producing Well

-- Entering the Well
Prior to initiating well control operations, several
safety precautions must be exercised. Production
chokes and the master valve are closed to halt fluid
production. The upper swab valve (if present) is
usually closed thus allowing workover equipment to be
flanged to the tree. This equipment could include
lubricators for wireline or mechanical set plugs, pump-
in lines, or BOP stacks for coil tubing or snubbing
equipment. Properly flanging the equipment to the tree
is essential for safe practices since a live well will
pressurize the equipment as soon as the master and
swab valves are opened.

-- Entering the Well
Back-pressure valves and plugs, wireline, or
mechanical set are normally employed while rigging
up surface equipment. A wireline plug may be set at
100 ft down in the tubing, while a mechanical back-
pressure valve is set in the bottom of the tree. These
tools aid in preventing blowouts in such cases as
flange leak detection while pressure testing the trees
and tree damage resulting from some accident
occurring during the rigging up operations.
Immediately prior to initiation of the kill procedures,
these valves and plugs may be removed.

-- Killing a Normal-Pressure Well
Type of fluids being produced from the well, formation
characteristics, tubing holes, and the condition of the
packer fluid in the annulus dictate kill procedures Most
can be categorized into those methods for killing
tubing with and without holes as well as for killing the
annulus. Killing an abnormal-pressure producing well
will require the same considerations as normal-
pressure wells in addition to other special problems.

Type of fluids being produced from the well, formation
characteristics, tubing holes, and the condition of the
packer fluid in the annulus dictate kill procedures Most
can be categorized into those methods for killing
tubing with and without holes as well as for killing the
annulus. Killing an abnormal-pressure producing well
will require the same considerations as normal-
pressure wells in addition to other special problems.

Most workover operations will require killing a
producing well that does not have a hole in the
tubing. The kill procedures for this situation
include bullheading, snub coil tubing, snub
jointed tubing, lubricating perforating the tubing,
and pulling the tubing out of the packer.

Bullheading is a term used to describe the pumping of
fluids into the formation In the case of well control, the
objective is to pump a workover fluid down the tubing
and drive the formation fluids out of the tubing,
through perforations and back into the formations.
Example 4.6 illustrates a typical bullheading procedure.

Example 4.6 Using the data given below, make the
necessary calculations and describe the steps to
bullhead the produced fluids into the formation.
Data:
Perforations at 9,100 ft
Formation pressure =9.0 ppg (normal)
Fracture gradient =16.5 ppg
THP = 795 psi
SITP = 3,457 psi
Tubing = 2yin., N-80, 6.4 Ib/ft.

Solution:
1. Calculate the required surface-imposed pressures to exceed
the formation fracture pressures (FP)
FP (INITIAL) = [ (16.5 ppg x 0.052 x 9,100 ft) - 795]
= 7,013 psi
FP (FINAL) = 7,808 psi - (0.052 x 9.0 ppg x 9,100 ft)
= 3,549 psi
2. Plot these values on Fig. 4.4
3. Calculate tubing capacities
9,100 ft x 0.005794 bbl/ft = 52.7 bbl
4. Determine the tubing burst pressure and plot on Fig. 4.4.
5. Slowly begin pumping 9.0 ppg brine water down the tubing. Do not
exceed any of the pressures shown on Fig. 4.4.
6. While pumping, monitor the pressures on the casing and adjacent strings
to detect any undesirable pressure buildup.

Fig. 4.4 shows several important points concerning
bullheading. The static pressures on the graph
indicate that the required bullhead pressures should
decrease as increased volumes of fluid are pumped
into the tubing. If this occurrence is not observed in
field operations, either the formation's ability to accept
fluid is decreasing (plugging) or gas is migrating
upward at a rate equal to the downward pump rate. In
addition, the required surface-imposed fracture
pressures decrease as the low density formation fluids
are displaced by the greater-density brine fluids.

Gas migration may be a serious problem in
workover operations, particularly when
bullheading techniques are used. Gas migration
is the upward movement of low-density fluids
through higher density fluids. Factors affecting
migration rates include relative densities and
viscosities, hole geometries, and influx size.

In the cases of formations with characteristics that
only allow low pump-in rates, upward gas migration
rates may equal or exceed the pump rates and result
in negating the advantages of bullheading. A practical
field-proven method can offset the ill effects of
migration. Viscosifiers such as polymers are added to
the workover fluid. Increased viscosity reduces the
migration rate of the gas.

In certain cases, bullheading will require that some
pressure is applied to the casing to prevent tubing
burst. This technique is generally required when the
pump-in pressure is high or when the tubing integrity
is questionable due to erosion or corrosion. One
should, however, determine the casing burst limits to
ensure that they are not exceeded.

Formation fluid types often affect the feasibility of
attempting bullheading procedures. Low viscosity
fluids such as gas will flow back through the formation
at rates greater than oil or water. In addition, gas will
have a reduced tendency to plug the formation as it
reverses flows. Certain completion systems such as
tubingless completions, however, may require
bullheading instead of some other alternative.

Coil tubing is often used to kill a producing well. The objective is
to circulate brine water down the small tubing and up the coil
tubing/production tubing annulus. A primary application for coil
tubing is in cases where the well cannot be killed by
bullheading because the wellbore is plugged with sand or junk.
Coil tubing may be restricted in gas wells due to strength
limitations of the tubing. In some cases, field experience has
shown that a coil tubing section filled with brine water will
exceed the tensile strength of the pipe. This is not usually the
case in oil wells because the buoyancy provided by the oil
reduces the overall tubing load.

Snubbing units are frequently used for high-pressure
well control problems. Snubbing small diameter pipe
into tubing provides the same type of well control
procedures as the coil tubing with the exception that
more time is required to snub in jointed pipe than
continuous coiled tubing. The primary advantages of
snubbing units over coil tubing are the ability to rotate
the jointed pipe and the greater pipe strength.

Lubrication is occasionally used for killing wells during
workover operations. It is a process that alternately
pumps a kill fluid into the tubing, and then a volume of
gas is allowed to escape from the well until the kill fluid
begins to escape through the choke. At this point,
brine water or other fluids are pumped into the tubing
and the cycle is restarted.

As each volume of brine is pumped into the
tubing, the SITP should decrease by a
calculated value until the well is eventually
killed. Caution must be exercised so that large
volumes of kill fluids are not allowed to escape
from the well during the bleeding phase.

The lubricate-and-bleed method is often employed for
two prime reasons. First, high pressure wells that
approach the rated pressure of the wellhead or tubing
may exceed the safe working limits of the equipment if
increased dynamic pumping pressures are imposed
such as with bullheading or snubbing methods. The
lubrication method can be used either to kill the well
completely or to reduce the shut-in pressures to a
level that will allow safe operations of other kill
methods.

Another application of the lubricate-and-bleed method
is in wells that have a plugged wellbore or perforations
that will not allow bullheading. The lubrication
procedures can be employed to kill the well without
the use of coil tubing or jointed concentric kill strings.
Lubrication is often a time-consuming process.
Another approach could complete the kill more quickly.
Example 4.7 illustrates a typical lubricate-and-bleed
method.

Example 4.7 A workover is planned for a high-
pressure well where the shut-in pressures approach
the rated working pressure of the wellhead equipment.
To minimize the possibility of an equipment failure, the
lubricate-and-bleed method will be used to reduce the
static pressures to a level that will allow safe
bullheading

Data:
Wellhead pressure rating == 5,000 psi
SITP = 4800 psi
Tubing = 2|-in., N-80, 4.7 Ib/ft
Perforations at 13,795 ft
Solution:
1. Estimate the expected pressure reduction for each
barrel of 9.0 ppg brine pumped into the well.
Tubing capacity = 0.003870 bbl/ft
= 258.4 ft/bbi (121 psi/bbi).

2. Rig up all surface equipment including pumps and a gas
flare line.
3. Open the choke to allow gas to escape from the well and
momentarily reduce the SITP.
4. Close the choke and pump in 9.0 ppg brine until the
dynamic tubing pressure reaches 4,800 psi.
5. Wait to allow the brine to fall in the tubing. The time will
range from 1/4 to 1 hour, depending on gas density,
pressure, and tubing size.
6. Open the choke and bleed gas until 9.0 ppg begins to
escape.
7. Close the choke and pump in 9.0 ppg brine water.
8. Continue the process until a low, safe working pressure is
attained. Fig. 4.5 illustrates sample results..

A certain amount of time is required for the kill fluids to
fall down the tubing after the pumping ceases. The
actual occurrence is not brine water falling through the
gas but rather gas migrating upward at 17-35 ft/min.
As an example, it would require a considerable time
lag for the fluid to fall or migrate downward to the
bottom of a 10,000-ft well. Therefore, after pumping it
is important to wait several minutes before bleeding
gas from the well to prevent bleeding the kill fluid
through the choke.

Perforating the tubing and circulating a kill fluid is the
primary method of killing producing wells other than
using inside-tubing kill procedures. A perforating tool
can make a circulating port in the tubing that will allow
direct communication with brine water. In this situation,
reverse circulation is usually done by pumping down
the annulus, through the perforation(s) and up the
tubing. This method requires that the packer fluid in
the annulus is in a circulatable condition and not
severely gelled or stratified.

Attention must be given to the selection of a
perforation tool. It is imperative that the tool,
mechanical or otherwise, have the capability to
perforate the tubing without damaging the adjacent
casing (especially when the tubing is close to the
casing). In addition, oriented perforating is desired for
multiple completions which may have several tubing
strings in the same casing annulus.

Pulling the tubing out of the packer to circulate a kill
fluid out of the bottom of the tubing is a technique
employed by many operators. This procedure involves
lifting the tubing a sufficient height to pull the seal
assembly from the polished bore in the packer. The
disadvantage of this method is that it requires that
sections of the production tree be removed or
unflanged to pick up the tubing. Once the tree is
unflanged, the major blowout prevention tool has been
altered.

Two types of completions are not suitable for this
method of well killing. Tubing systems with long
sections of the seal assembly could require picking the
tubing string up higher than the workover rig will allow.
Tubingless completions do not employ a packer
system. In these cases, the methods previously
described must be used.

Killing a producing well that has a hole in the tubing or
a leak in the packer requires additional considerations.
The primary concern is determining the location of the
hole. Additional concerns include the effect of the
formation pressure exposed on the casing and the kill
procedure that will be most effective in each case.

Determining the location of the tubing hole generally
requires an on-site evaluation of the situation. The
hole or leak will be indicated by pressure on the
casing string(s). The most common method of locating
the leak is by rigging surface equipment and pumping
a volume of brine water until it is returned to the choke
on the annulus. This volume can be used to calculate
the location of the hole.

Example 4.8 A workover was to be performed to
repair a tubing string that had a leak. After the
pumping equipment was rigged up on the well, a 38-
barrel volume of saltwater was pumped down the
tubing before it was detected at the choke. Using the
data given below, what was the depth of the hole in
the tubing?

Data:
Tubing = 2i--in., 4.7 Ib/ft
Casing = 7-in., 23 Ib/ft
Tubing capacity = 0.003870 bbl/ft
Annulus capacity = 0.03388 bbl/ft
Solution:
Using the data given above, the hole location would be
determined as follows:
Volume pumped/cubing + annular) capacity = Depth of hole
38 bbl/(0.003870 + 0.03388) bbl/ft = Depth
38 bbl/0.03775 bbl/ft = 1,006 ft

Deep holes can generally be killed in a
conventional circulation manner. Shallow to
medium-depth holes will require snubbing coil
tubing or jointed pipe or lubrication. Bullheading
can be attempted only if the dynamic pressures
do not exceed the casing burst pressures..

A loss of integrity in the tubing string resulting
from a hole or leak will cause a pressure
buildup on the casing or annulus. Killing the
tubing by lubricating or snubbing will not
necessarily kill the annulus.

In this case, it is necessary to perform a kill on
the annulus using one of the previously
described methods. These include bullheading,
lubricating, or reverse circulating. With these
procedures gas migration can be a serious
problem when pumping down the annulus.

Various operators have used a second short tubing
string (kill string) for this application. It is run as a dual
string, but it is not used as a flow string. If pressure
should build up on the casing, kill fluid can be
circulated throughout the upper sections of the
annulus without disturbing the flowing tubing string.
Kill strings are not employed in most applications.

-- Abnormal-Pressure Producing Well
The concepts and procedures for killing an
abnormal-pressure producing well are
essentially the same as those for a normal
pressure well. The primary exception is
the use of high-density kill fluids in place of
9.0 ppg brine water or other fluids of low
density. Calculating the kill density, as
previously described, will show the weight
needed.

Kill During Workover
Burst pressures of the tubular goods may
be a limitation with high-pressure wells.
Tubing holes and leaks become a serious
concern because the casing may be
exposed to pressure. In addition, abnormal-
pressure wells often have additional
problems such as corrosion and erosion
that require special consideration when
using tubular goods with low burst-pressure
ratings.

-- Circulation Procedures
When the work string is near the bottom of the well,
circulating out the kick with a kill fluid is the
approach most often used. The surface equipment
employed in the procedure includes the pumps
and a choke to apply a back pressure. The kill fluid
is usually fresh or brine water but will occasionally
be a weighted fluid such as calcium bromide or
heavy muds. The circulation route can be down
the work string and up the annulus (the long way),
or down the annulus and up the tubing(the short
way).

Long Circulation
The long or regular method of circulation
involves pumping a kill fluid down the
tubing or work string and up the annulus
while displacing the kick fluids during the
circulation. A simple schematic
representation is seen in Fig.4 6 The primary
advantage of this method is that kill
pressures are lower than those seen while
killing an identical kick with the reverse-out
procedure. Gas migration is not often a
severe problem with this procedure.

Long Circulation

Long Circulation
The required kill fluid will be of sufficient density
to balance he formation pressure at the bottom of
the well. This amount of mud weight will kill the
wel1 and minimize the possibility of inducing a
fracture into the formation. The kill mud weight is
determined using an equation similar to that
shown in Eq.
KWM == SITP x 19.23/Depth
Where:
KWM = Kill weight mud, ppg
SITP = Shut-in tubing (work string) pressure, psi
Depth = True vertical depth, ft
19.23 = Conversion constant, ppg/psi/ft

Long Circulation
This equation is sometimes written with the
constant 0.052 in the divisor or (more properly) by
19.25 in the numerator. The slight difference due
to rounding is inconsequential in the field. Either
equation can be used.
In most cases, the kill fluid will be 9.0 ppg brine
water or lower densities since formation pressures
generally encountered are normal or less-than-
normal resulting from depletion. Higher kill mud
weights are often required as in the cases of
abnormal formation pressures or where a wellbore
obstruction prevents running the work string to
bottom.

Long Circulation
Circulating kill fluids will cause the pumping
pressures to change (Fig.4.7-4.10). The
causes for the changes include dynamic
pumping pressures, gas in the tubing,
displacing low-density workover fluids with
high-density kill muds, and effects of the
choke restriction. Fig. 4.7 and 4.9 illustrate
the effect of pumping pressures added to
static shut-in pressures.

Long Circulation
Kill procedure requires maintaining the
pumping pressure at the designated levels,
such as in Figs. 4.7 and 4.9. The constant
bottomhole pressure method uses pump
pressure to control the bottomhole pressure
at a value slightly greater than formation
pressure. The choke is used to raise or
lower the pumping pressure to the desired
value.

Long Circulation
If high-density kill fluid is required to kill the
kick, a kill sheet may be an aid in
determining the proper amounts of pressure
to maintain on the pump. The kill sheet
helps calculate kill fluid densities and
expected pressure changes on the pumping
pressures. It contains other items such as
work string volumes. A sample kill sheet is
shown in Fig. 4.11.

Long Circulation
The annulus pressure will experience many
changes during the course of the kick-killing
procedures. The changes result from gas
expansion, gas migration, choke changes,
and high kill mud weights when used. It
should be noted that the primary objective
during kick killing is maintaining the
required pumping pressures by adjusting
the casing pressure as necessary.

Short (Reverse) Circulation
Reverse circulation involves pumping kill
fluids down the annulus and displacing the
kick fluids up the tubing. A typical
schematic representation is shown in Fig.
4.13. This procedure requires that a choke
be placed in the standpipe or that the
surface equipment can be arranged in such
a manner that kick fluids are conducted
through the standpipe to the choke. The
choke manifold shown in Chapter 3 allows
normal and reverse circulation procedures.

Reverse circulation advantages include a
significant reduction in the time required to
circulate the kick fluid from the well and
better control of high surface pressures due
to the generally greater burst strength of
tubing and work strings as compared to
casing.

The disadvantages of reverse circulation
include possible plugging when attempting
to reverse flow if bit jets or circulating ports
are in the work string. The slow circulating
rates used in the reverse procedure may
allow gas to migrate up the annulus at a rate
greater than the downward flow rate.

The reverse circulation method utilizes the
pumping casing pressure to monitor the kill
operation. The standpipe choke is used to
adjust the pumping casing pressure to the
required values. Typical casing and work
string pressures are shown in Figure 4.14
for the reverse circulation procedure.

The gas migration problem, which may be
severe in the reverse method, must be
considered in determining the application of
the method. These rates may range from 30
ft/min in the case of gas migrating through
fresh water to as low as 2 ft/min (or less) in
heavy viscous muds. Gas migration can be
controlled by increasing the pumping rate or
by adding to the kill fluid a viscosifier which
will decrease the upward flow rate of the gas.

Workover Well Control Problems
The primary causes for workover problems
are that known producing intervals are
exposed to the wellbore and that workover
fluids generally consist of only clean brine
water. These brines have low viscosities
which maximize gas migration rates and
minimize wall-building fluid loss control
characteristics.

Well workovers on low-pressure permeable zones
must contend with fluid loss or seepage. This may
create a well control problem if a sufficient volume
of fluid is lost. This might reduce the hydrostatic
pressure and allow a kick to occur. The most
common method to reduce seepage and prevent
kicks is using a formation plugging material such
as viscous polymer pills or calcium carbonate.
After the workover is completed, the plugging
agents are removed by backflow or acidizing.

Between-interval flows often occur during
workovers when high and low pressure
zones are exposed in the wellbore. The low-
pressure zones will not support a high
density kill fluid necessary to control the
other interval. Remedies to this problem
include polymer plugging or calcium
carbonate to seal the low pressure zone and
mechanical plugs to isolate the intervals.

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