May
2001 Vol. 222 No. 5
Feature Article
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WELL
CONTROL/INTERVENTION
Well control during well intervention Part 3
Avoiding formation damage while pumping through coiled tubing
Recommendations
for implementing CT-conveyed well control within existing production
tubulars to aid the user in conducting well intervention operations with
minimal induced formation damage
Alex
Sas-Jaworsky II, SAS Industries, Inc., Houston
oiled
tubing (CT) services are used frequently to conduct kill operations
concentric to existing production tubulars. These kill operations
typically are performed to temporarily effect a hydrostatic balance of
formation pressure at the exposed completion.
For those cases
in which wellbore operations subsequent to the kill program are not
intended to return the existing completion to active status, formation
damage induced by the kill practice is generally of little
consequence. However, where return of the existing completion to
active status is desired, the well control operation must be conducted
with a complete understanding of the pressure balance and effect of
kill fluid circulation on the completion. Many practices used in
performing concentric tubing well control services lead to varying
degrees of formation damage and impair completion flow performance.
This article
discusses alternative well control kill processes and the potential
for reducing formation damage by using CT well control practices.
Recommendations for planning and implementing CT-conveyed well control
programs within existing production tubulars are provided to guide the
user in conducting well control operations with minimal induced
formation damage.
Well
Control Practices Using Coiled Tubing
There are
several benefits to the use of CT services when conducting well kill
operations, with the major benefits providing the ability to:
- Maintain
continuous pumping operations while manipulating the CT string
within the wellbore
- Perform
these operations with surface pressure present.
As such,
circulation-type well control programs performed with CT offer a high
degree of fluid placement control. In addition, the accumulations of
pipe dope, rust, scale and associated debris from completion tubulars
are circulated out of the wellbore during the initial pumping process
and are not displaced into the exposed formation, further mitigating
formation damage.
When performing
a circulation-type well control operation, a constant bottomhole
pressure (CBP) condition should be maintained throughout the kill
program. The CBP practice is intended to provide the desired balance
of formation pressure through a combination of the hydrostatic
pressure created within the wellbore for given fluid columns and the
pressure held at surface for the prescribed choke pressure schedule.
Using the CBP well control practice, the formation pressure is held at
or slightly above balance during the circulation program.
With the
balanced bottomhole pressure condition, additional influx of reservoir
fluids into the wellbore is eliminated. Of equal importance; however,
is the reduction of kill-weight fluid losses into the formation,
reducing the potential for induced formation damage within the
completion interval.
In addition, a
third variable related to fluids circulation must be included in the
CBP well control program analysis. During any fluids circulating
program, frictional pressure losses will be generated within the
wellbore annuli, which act as an additional applied pressure onto the
exposed formation. Depending upon the amount of annuli pressure
applied to the exposed formation, losses of kill-weight fluids can be
expected, contributing to post well control formation damage, where
fluid compatibility is an issue.
The following
discussion reviews the various design issues that should be addressed
when planning and implementing well control fluid circulation
operations using CT services with respect to minimizing induced
formation damage.
Selection
of Kill-Weight Fluid
The most common
well control kill fluids selected for minimal induced formation damage
are completion brines blended to the prescribed fluid density. Issues
related to selection of the most appropriate kill-weight fluid type,
chemistry and compatibility with the specified formation (with respect
to minimizing formation damage) may be found in supporting published
work. For the purpose of citing examples, generic completion brines
will be used.
Typically,
completion fluids are a class of liquids described as high-density
brines that behave as clear-penetrating liquids when placed across
permeable formations. In addition to the high-density property needed
to create the desired hydrostatic pressure balance, completion brines
may be filtered through diatomaceous earth (DE) presses or filter
cartridge pods to eliminate solids that contribute to formation
plugging. As a result, losses of high-density brines to the formation
can be expected. The loss volume will be dependent upon the
near-reservoir permeability within the completion, kill-weight fluid
properties and pressure applied to the formation within the annuli
during the circulation program.
Using a
modification of the Darcy steady-state radial flow equation (Eq. 1),
an approximation of the volume loss of the high-density brine to the
formation can be calculated for a given pressure differential at the
completion interval, assuming that data for required reservoir
parameters, and the properties for the kill-weight fluid at reservoir
conditions, is available.
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(1) |
For initial
fluid losses to the completion interval, Eq. 1 must be assumed to be
in an unsteady-state condition and represents liquid-liquid
displacement through the completion interval. The viscosity of the
kill-weight completion fluid (µ) at the given reservoir
temperature should be used, along with a formation volume factor (B)
of 1.00. Reservoir permeability and formation height (Kh)
values obtained from production tests may be used to predict initial
fluid losses to the formation due to applied wellbore annuli pressure.
For example, a
reservoir having a Kh value of 5,000 md-ft and skin factor (S)
of 5.0 is subjected to a kill program using a 10-ppg CaCl2
completion brine having a viscosity of 0.50 cP at a reservoir
temperature of 214°F. Assuming a reservoir drainage radius of
1,000 ft and a wellbore radius of 0.54 ft, the predicted amount of
completion brine in bpm lost to the formation per psig applied annuli
pressure is shown below.
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(2) |
In the above
example, an estimated 0.0034 bpm of brine is displaced into the
formation interval for every one psig of differential pressure applied
from the wellbore to the reservoir. For a circulation program in which
a wellbore pressure imbalance of 100 psig is developed within the
annuli (through frictional pressure losses or applied surface
pressure), the imposed differential pressure against the exposed
formation yields an estimated kill-weight fluid loss rate of 0.34 bpm
to the completion interval.
Fluid Loss
Control
For CT well
control operations, the loss of kill-weight fluid to the formation may
pose significant problems related to surface tankage volume
availability, increased cost for replacement of high-density brine
volumes and maintaining the desired fluid circulation / displacement
rates within the wellbore. In the example fluid loss prediction seen
above, a 240-min circulation kill, generating a constant annular
frictional pressure loss of 100 psig above the balance pressure, will
result in an estimated 82 bbl of kill-weight fluid lost to the
formation.
Since CT well
control operations typically are conducted with limited fluid volume
tankage available at surface, the well kill program must take into
consideration the volume of fluid loss anticipated during the
circulation program.
A secondary
problem can occur when attempting to perform a well kill program
within a wellbore where part, or all, of the exposed completion
interval is gas bearing. In this situation, fluid losses to the
formation will occur as the result of gas-liquid override, regardless
of the pressure balance maintained within the wellbore. Due to
differences in fluid density and viscosity, clear-penetrating liquids
will permeate into the completion interval, providing an avenue for
gas to override the liquid and enter the wellbore. As this gas influx
migrates to surface, the expansion of gas will displace wellbore
liquids to the formation. This reduction in hydrostatic height of the
fluid column increases the underbalanced condition within the well and
promotes additional gas influx, compromising the well control effort.
In completion
intervals where excessive fluid losses are expected due to high
permeability or gas-liquid override, it is recommended that a fluid
loss control program be incorporated into the well control operation.
The fluid loss prevention method should impose minimal damage to the
formation and be removed easily prior to or during well production.
The fluid loss mechanisms described below are designed to allow well
control kill operations to be conducted with a minimum of induced
formation damage. These include viscous gel pills, graded-sand plugs,
and mechanical plugs or packers.
Gelled
pills. In general, these fluid loss control mechanisms are brine
viscosifiers, which include linear gels and cross-linked gels. These
pills may be blended with the high-density brine selected as the
kill-weight fluid or a compatible brine and serve to significantly
reduce the amount of fluid loss to the formation by creating a
temporary barrier of high-viscosity media across the exposed
formation. The placement of this type of fluid loss control pill does
not restrict access to the completion interval if intervention work is
required subsequent to the kill program. Due to the complex nature of
these viscous gels, it is critical that compatibility tests are run
between the selected gel system and the formation fluid / rock
chemistry to ensure that secondary damage due to precipitation does
not occur. The removal process may require external breakers or
contact with low-pH acid solutions.
Sized-salt
pills. Another mechanism used to control fluid loss is a saturated
graded-salt pill. This type of pill is also blended with the
kill-weight brine and used to create a barrier to fluid flow across
the exposed completion interval by forming a mechanical bridge with
the salt particles. The placement of a sized-salt may not restrict
access to the completion interval if intervention work is required
following the kill program due to settling. The removal process may
require a high-energy wash with an undersaturated solution to dissolve
the salt bridging particles.
Graded-sand
plugs. In some situations, a graded-sand plug may be circulated
down the CT string and placed across the completion interval to
blanket the exposed formation. This type of plug provides protection
from formation damage that could occur during well service work
performed subsequent to the well kill program. In general, the smaller
the sand sieve size, the more effective the plug for fluid loss
control. However, small sand grain sizes may travel into the pore
spaces of the exposed formation, creating a secondary damage
mechanism. Therefore, sand selected for this service should have high
sphericity (roundness) and be commercially sieved to a mesh range that
will bridge against the formation face and minimize sand entry into
the pore spaces when placed across the completion interval.
Mechanical
plugs and packers. Depending upon the post-well-kill service to be
performed, the completion interval may be mechanically isolated from
surface with the use of through-tubing plugs or packers. If access to
the completion interval is not required, then an assessment may be
made to determine if mechanical isolation will provide the desired
barrier to fluid loss and mitigation of formation damage for the given
well.
This isolation
option requires that the borehole ID be within the applicable size
range of the inflatable plug or packer device, which will be
transported through and set in the existing completion tubulars.
Although this isolation mechanism should create the necessary pressure
barrier within the wellbore, the well control program still should
incorporate kill-weight fluids circulated above the inflatable device
to create a hydrostatic balance across the elastomeric sealing
elements. Further sealing efficiency may be obtained by spotting a
sand plug on top of the inflatable device prior to circulating the
kill-weight fluid into the wellbore.
Kill Fluid
Circulation and Placement
The unique
ability of continuous pumping through CT, while manipulating the
position of the tubing within the wellbore, provides the means to
control the placement of the fluid loss treatment with a high degree
of accuracy. Depending upon completion design and wellbore
orientation, the kill-weight fluid circulation program may require
added preparation to ensure effective placement of the kill fluid
and/or viscous gel pill.
Proper well
control programs require that the wellbore segment located below the
base of the completion interval be prepared to support a column of
kill-weight fluids without the possibility of gravity segregation
and/or contamination. Prior to commencing well control operations, the
actual plug-back depth should be determined and the fluid volume to
fill the wellbore segment between the base of the completion interval
and plug-back TD should be calculated.
If the
completion design allows for mechanical isolation of the wellbore
below the exposed interval, then a through-tubing type plug or packer
may be set at a depth that reduces the volume of the exposed wellbore
segment. However, if it is not feasible to mechanically isolate the
lower wellbore segment, then an additional circulation operation
should be conducted to displace the fluid below the completion
interval with the required kill-weight fluid density.
Placement
of viscous gelled pills. In a typical viscous-gel pill placement
program, the CT fluid nozzle is located within the wellbore at a depth
below the exposed completion interval. The gelled-pill treatment
volume is circulated down the CT string to the nozzle, with displaced
wellbore fluids returned and captured at the surface. Based on
observed fluid pumping rates through the CT string, the arrival of the
fluid loss control pill at the CT nozzle downhole can be accurately
timed. When the fluid loss control pill begins to exit the CT nozzle,
a specified volume of the pill is displaced into the wellbore to
create an interface between the nozzle and the resident wellbore
fluids, Fig. 1a.
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Fig.
1. Placement of viscous gelled pills: a) Specified pill
volume is displaced into wellbore to create interface between
nozzle and resident wellbore fluids; b) "Puddling"
is conducted by slowly pulling CT nozzle up wellbore at a
speed commensurate with fluid pump rate, keeping position of
gelled-pill interface at desired height above nozzle; c) To
ensure entire interval is covered by fluid loss control
treatment, calculated pill volume should include excess that
will accumulate above top of completion interval; d) Specified
pill height above completion interval should serve as upper
position where CT nozzle will be placed when circulating
clear-penetrating kill-weight fluid. |
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If the height
of the completion interval to be treated is short (<30 ft), then
the position of the CT nozzle may remain stationary, and circulation
of the viscous gel pill continued until the desired gel column height
is achieved. To ensure that the gelled pill is properly placed across
a longer completion interval, the CT string typically is manipulated
during the circulation program.
This fluids
placement practice, commonly described as "puddling," is
conducted by slowly pulling the CT nozzle up the wellbore at a speed
commensurate with the fluids pump rate, which keeps the position of
the gelled pill interface at the desired height above the nozzle, Fig.
1b. This operation ensures that the pill is effectively placed across
the completion interval with minimal contamination from resident
wellbore fluids.
Note that the
description of the above puddling process is valid for vertical and
moderately deviated wellbore orientations. In highly deviated and
horizontal completion intervals, gravity segregation of the
kill-weight gelled pill requires some modification to this procedure.
For this
application, the CT nozzle should be run to the plug-back TD of the
horizontal borehole and circulation of the prescribed kill-weight
gelled pill initiated. The circulation of the high-density viscous
pill should fill a minimum of 80% of the horizontal borehole volume
before commencing the CT puddling procedure. During this initial
circulation phase, the less dense resident fluids in the borehole can
segregate into the ullage space at the top of the horizontal borehole.
Once a
sufficient volume of the gelled pill is placed in the borehole, pump
rate is increased, creating a high-energy plume at the CT nozzle. Upon
extraction of the CT nozzle, remaining resident fluids are displaced
forward and ultimately circulated out of the wellbore.
To ensure that
the entire completion interval is covered by the fluid loss control
treatment, the calculated volume of pill needed should include excess
volume, which will accumulate above the top of the completion
interval, Fig. 1c. The desired height of the viscous gel pill above
the completion interval is a function of the predicted effectiveness
of the gel pill for the target formation. As such, the recommended
height of the pill in excess of the completion interval top should be
determined on a job-by-job basis for the respective gel type selected.
The specified pill height above the completion interval should serve
as the upper position where the CT nozzle will be placed when
conducting circulation of the clear-penetrating kill-weight fluid,
Fig. 1d.
Placement
of sand plugs. Where placement of sand plugs is desirable for use
as a fluid loss control mechanism, planning must include onsite
blending of the sieved sand within the desired linear gel, minimum
pump rate through the CT string (to ensure pumping control of the
slurry) and volume of the individual slurry batches to be pumped. In
general, the slurry batch volume should be sized no larger than the
capacity of the CT string deployed within the wellbore. This will
allow for measured displacements within the wellbore and minimize sand
settling within the CT on the reel at surface if the nozzle becomes
plugged during the placement program.
Once the slurry
volume reaches the nozzle, the CT should be retrieved up the wellbore
at a speed commensurate with the sand settling rate for the given gel
concentration, Fig. 2. Note that the pump rate of the sand slurry
should not create an annular velocity that exceeds the sand settling
rate for the given gel system.
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Fig.
2. Sand plugs may be placed as a fluid loss control
mechanism. Once slurry volume reaches the nozzle, coiled
tubing is retrieved at a speed commensurate with sand settling
rate. |
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After the
volume of slurry is displaced through the CT string, maintain
circulation and displace a volume of fluid equal to the slurry volume
previously pumped. If a fill-up depth check is warranted, then the
pumps should be shut down and the CT run slowly into the wellbore to
tag the top of the sand plug. The slurry mixing and pumping process
should be continued until the top of the sand plug reaches the desired
depth within the wellbore. Sand plug height above the completion
interval should then serve as the upper position where the CT nozzle
will be placed when conducting circulation of the clear-penetrating
kill-weight fluid.
Literature
Cited
1
World Oils Coiled Tubing Handbook, 3rd Edition, Gulf
Publishing Company, Houston, Texas, 1998.
2
Sas-Jaworsky, A., and A. Ghalambor, "Considerations For
Conducting Coiled Tubing Well Control Operations to Minimize Formation
Impairment," SPE paper 58792, SPE International Symposium on
Formation Damage Control, Lafayette, La., February 23 24, 2000.
3
Bishop, S. R., "The Experimental Investigation of Formation
Damage Due to the Induced Flocculation of Clays Within a Sandstone
Pore Structure by a High Salinity Brine," SPE paper 38156, SPE
European Formation Damage Conference, The Hague, Netherlands, June 2
3, 1997.
4
Foxenberg, W. E., et al., "Effects of Completion Fluid Loss on
Well Productivity," SPE paper 31137, SPE International Symposium
on Formation Damage Control, Lafayette, La, February 14 15,
1996.
5
Houchin,L. R., et al., "An Analysis of Formation Damage by
Completion Fluids at High Temperatures," SPE paper 23143,
Offshore Europe Conf., Aberdeen, September 3 6, 1991.
6
Baijal, S. K., et al., "A Practical Approach to Prevent Formation
Damage by High-Density Brines During the Completion Process," SPE
paper 21674, Production Operations Symposium, Oklahoma City, Okla,
April 7 9, 1991.
7
Morgenthaler, L. N., "Formation Damage Tests of High-Density
Brine Completion Fluids," SPE paper 13811, SPE Production
Operations Symposium, Oklahoma City, Okla., March 10 12, 1985.
8
Allen, F. L., et al., "Initial Study of Temperature and Pressure
Effects on Formation Damage by Completion Fluids," SPE paper
12488, Formation Damage Control Symposium, Bakersfield, Calif.,
February 13 14, 1984.
9
Syed, A. Ali, et al., "New Test Identifies Completion Fluid
Compatibility Problems," Oil & Gas Journal, August
25, 1997, pp. 95 101.
10
Hodge, R. M., "HEC Precipitation at Elevated Temperature: An
Unexpected Source of Formation Damage," SPE paper 38155, SPE
European Formation Damage Conference, The Hague, Netherlands, June 2
3, 1997.
11
Hardy, M., "The Unexpected Advantages of a Temporary Fluid-Loss
Control Pill," SPE paper 37293, SPE International Symposium on
Oilfield Chemistry, Houston, Texas, February 18 21, 1997.
12
Himes, R. E., et al., "Reversible Crosslinkable Polymer for
Fluid-Loss Control," SPE paper 27373, SPE International Symposium
on Formation Damage Control, Lafayette, La., February 7 10,
1994.
13
Johnson, M. H., "Completion Fluid-Loss Control Using
Particulates," SPE paper 27371, SPE International Symposium on
Formation Damage Control, Lafayette, La., February 7 10, 1994.
14
Blauch, M. E., et al., "Fluid-Loss Control Using Crosslinkable
HEC in High-Permeability Offshore Flexure Trend Completions," SPE
paper 19752, 64th SPE ATCE, San Antonio, Texas, October 8 11,
1989.
15
Chambers, M. J., "Laying Sand Plugs With Coiled Tubing,"
SPE paper 25496, Production Operations Symposium, Oklahoma City,
Okla., March 21 23, 1993.
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Coming
Installments
Part
4 Proper selection of coiled tubing surface and
downhole well control equipment.
Part
5 Well control considerations during intervention
using snubbing equipment.
Part
6 Planning a hydraulics program for well
intervention well control. |
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The
author |
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Alexander
Sas-Jaworsky II is founder and principal engineer of
SAS Industries, Inc., formed in 1995 and specializing in
mechanical testing, training and service consultation for all
aspects of applied coiled tubing technology. He began his career
with Conoco after receiving a BS in petroleum engineering at the
University of Southwestern Louisiana in 1982, and he worked for
various coiled tubing companies before and while attending
college. He worked in several Conoco divisions as a production
engineer before transferring to the Conoco Houston Production
Technology group in December 1990 as worldwide concentric workover
consultant for coiled tubing and snubbing. He is a registered
professional engineer in Louisiana and Texas, SPE member, and
serves on API committee 3/subcommittee16 as chairman of the well
intervention well control task group. |
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Part
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Part
2 |
Part
4 |
Part
5 |
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