Jan.
2001 Vol. 222 No. 1
Feature Article
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WELL
CONTROL / INTERVENTION
Well control during well intervention
PART 1 Considerations for design and
placement of kill weight fluids
To
plan a more effective well control program, several important issues
must be considered, including the determination of fluid kill-weight,
space availability for required fluid tankage and kill fluid pumping
schedules
Alex
Sas-Jaworsky II, Sas Industries, Inc., Houston
uring
the life cycle of a conventional completion, wellbore operations may
necessitate hydrostatically balancing the formation pressure to
achieve zero surface well pressure. For these types of operations,
well control practices described as "kill programs" are
employed to replace the resident wellbore fluids with a column of
liquid of sufficient density to hydrostatically balance formation
pressure. Depending upon the operations to be performed after the well
is killed, there are several ways in which well control can be
implemented using a variety of fluid rheology types and densities.
Conventional
completion designs utilize concentric tubulars assembled to provide
desired flow conduits within the wellbore. During installation of the
completion equipment, the tubing provides the natural flow path for
circulation of pumped fluids from surface. However, once completion
tubulars are pressure-isolated downhole using packers or other flow
control devices, the circulation pathway from the surface to the
completion typically is not available.
If circulation
of fluids cannot be established through the completion equipment
installed within the wellbore, a well kill pumping technique described
as "bullheading" may be used. This well control operation is
performed by pumping the kill-weight density liquids through the
surface wellhead equipment at a rate sufficient to displace the
resident well fluids from the tubulars and back into the exposed
completion interval. Although effective, bullhead kills offer minimal
control of fluid placement within the wellbore and have a high
potential for inducing formation damage. If operations conducted upon
completion of the well control program do not require continued
service from the completion interval, then formation damage mitigation
is not a concern and the bullhead kill method is a viable option.
However, where
the well control operation is intended as a temporary pressure balance
condition and the exposed completion interval is intended to be
returned to production, the design of the well-kill program should
focus on achieving hydrostatic pressure balance with a minimum of
induced formation damage. In this situation, concentric tube well
intervention services have been used successfully to establish the
fluids circulation flow path from surface to the completion interval.
Using these types of service equipment, the kill operation can be
performed by circulating out the resident wellbore fluids and
replacing the wellbore volume with a kill-weight liquid having the
desired rheology and density for the prescribed service.
Concentric-Tube
Well Intervention Services
Well
completions are designed with considerations for performing either
wireline or tubing-conveyed, through-tubing intervention services
within the planned life cycle of the wellbore. Tubing-conveyed,
through-tubing well intervention services such as hydraulic workover
(HWO) and coiled tubing (CT) are capable of performing a variety of
services, with and without surface well pressure present, and are
amply suited for pumping and circulating fluids within the completion
tubulars. A comparison of these two systems, however, reveals that the
well control programs are implemented in different manners.
By design, the
HWO system utilizes jointed tubing, which incorporates back-pressure
valves in the workstring BHA, and which must interrupt pumping
services when making and breaking connections. Implementation of HWO
well control operations typically involves deployment of the
workstring concentric to the existing completion tubulars, with
intermittent pumping down the workstring to fill the pipe and ensure
that the ID is free from blockage. The workstring is run to the
proposed kill depth, at which time pumping operations are initiated
for the purpose of circulating out the resident well fluids with the
kill-weight fluid designed to achieve pressure balance.
The kill
program is typically conducted with the HWO workstring stationary, and
once hydrostatic pressure balance is achieved, fluid circulation is
halted and the workstring is extracted from the wellbore. During
workstring extraction, the kill-weight fluid pumping operation
generally is directed into the flowcross within the well control
stack, maintaining the fluid column height in the annulus.
In contrast, CT
services utilize a continuous-length tubing string, which can be
deployed and retrieved throughout the prescribed operation without
interrupting pumping. The continuous-pumping capability of CT affords
a greater degree of fluid placement control within the wellbore and
allows variations to standard kill programs to achieve the desired
hydrostatic pressure balance. The CT string can be deployed and
retrieved rapidly in comparison to HWO systems, reducing the time
needed to perform the desired well control service. In addition, with
the introduction of higher yield strength grades of CT, the upper
pressure limits for safely performing CT services has increased
dramatically.
Although the
continuous-length CT product offers benefits in reduced service time
and fluids placement over HWO systems, CT has a finite service life
due to bend-cycle fatigue that occurs as a consequence of the CT
operation. Therefore, it is recommended that the user obtain the life
management log for the designated CT string (with the prediction for
remaining service life) from the CT vendor prior to dispatching the
equipment.
Pre-Job
Planning And Well Control Review
Prior to
implementing concentric tube well control operations, several issues
must be addressed to define the nature of the kill operation, assess
the risk factors and determine the most appropriate method for
implementing the desired kill. Unlike well control contingency
planning for drilling or completion operations, the level and quality
of job-critical information available on location is typically
insufficient to effectively implement well kill operations in a safe
and prudent manner. Therefore, when preparing to perform
through-tubing well control operations, a dedicated effort must be
made to obtain the most reliable information regarding wellbore design
and condition, as well as formation pressure and completion integrity
before dispatching the well intervention equipment to location.
Completion
details and wellbore orientation. Proper design of any
concentric-tubing well control operation requires that wellbore
completion information and borehole orientation be fully incorporated
into the well control plan, Fig. 1. The wellbore schematic for a given
completion should provide information on the type and size of the
wellhead tree connection and sizes of tubular goods installed in the
wellbore, along with recorded setting depths.
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Fig.
1. Wellbore completion information and borehole
orientation are key to the proper design of concentric-tubing
well control operations. Schematic should include type and
size of wellhead tree connection, sizes of tubular goods
installed and recorded setting depths. |
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The measured
depth (MD) values reflect the tubing tally records provided in the
completion detail and are needed to calculate fill-up volumes for the
flow-path conduit from the completion interval to surface. Of greater
importance, however, is the corresponding depth value shown as true
vertical depth (TVD). TVD measurements are required to calculate
hydrostatic pressure exerted on the formation from a standing column
of fluid of a given density. Therefore, proper well control planning
requires that all completion tubular design components and reservoir
depth measurements be reported in both MD and TVD values.
The
aforementioned MD and TVD measurements are referenced from the rig
floor, typically referred to as KB. Depending upon how and where the
wellbore was drilled, the values for KB may be reported as distance
from ground level (onshore) or distance from an installed component
located on the wellbore structure (e.g., tubing hanger, lowest most
flange, etc.). With the exception of concentric-tubing operations
performed from the rig floor, depths must be corrected to the given
reference to ensure that the workstring depth readings can be
correlated back to MD and TVD positions within the wellbore.
Fluid
hydrostatics and pressure balance concerns. Prior to
commencing any well control operation, the kill-weight fluid density
needed to balance the formation pressure must be determined. The
equation commonly used to calculate fluid density r (ppg) to
balance a given pressure P (psig) with a true vertical fluid column
height HHyd (ft) is given below:
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This
calculation provides the user with a value equal to the "average"
fluid density needed to balance the given reservoir pressure with a
standing column of the fluid to a specified TVD. The fluid column
height measurement in this calculation must be corrected for
differences with KB measurements and reflect the point in the surface
production tree or well control stack where the top of the kill-weight
fluid column will be located. In general, the top-of-column point
should be located within the surface production tree, which ensures
that the desired hydrostatic pressure balance is maintained at the
wellhead after the service riser and well control stack are removed.
However, rig-up
for a prescribed well intervention service may locate the returns
circulation port in the well control stack riser at a point
significantly higher than the surface tree. In this situation, the
primary kill-weight fluid circulation program may need to locate the
top-of-column point at the returns line elevation, with secondary kill
contingencies prepared for placing the kill-weight fluid column top at
the desired location in the surface production tree.
Attention also
should be paid to the predicted change in kill-weight fluid density
due to changes in temperature and pressure within the wellbore. Fluid
density decreases with an increase in temperature and increases with
an increase in pressure. Further, the change in fluid density due to
temperature and pressure depends upon the fluid chemistry and amount
of dissolved or suspended solids in the fluid.
Since the "average"
fluid density calculated in the above equation does not account for
fluid property changes due to temperature and pressure conditions,
this value should be used only as a reference density when selecting
the desired kill-weight fluid. Once the kill-weight fluid type is
identified, the fluid supplier should provide a recommended blending
density for surface conditions that yields the desired hydrostatic
pressure balance at the specified fluid column TVD when the fluid
reaches equilibrium temperature within the wellbore.
An example of
the change in fluid density due to temperature and pressure for given
wellbore conditions is seen in Fig. 2. In this example, the "average"
kill-weight fluid density needed to balance the 5,200-psig reservoir
pressure is calculated to be 10 ppg. As such, the blended CaCl2
kill-weight fluid must yield an apparent density of 10.15 ppg at 74°F
to achieve an "average" kill-weight density of 10 ppg at the
temperatures and hydrostatic pressures seen in the example wellbore.
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Fig.
2. This example illustrates the change in fluid density
due to temperature and pressure for given wellbore conditions.
The average kill-weight fluid density needed to balance the
5,200-psig reservoir pressure is 10 ppg. The blended CaCl2
kill-weight fluid must yield an apparent density of 10.15 ppg
at 74°F to achieve an average kill-weight density of 10
ppg under the temperature and pressure in the example. |
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Therefore,
kill-weight fluid density must be adjusted for the surface mixing
temperature to obtain the desired density at wellbore temperatures.
When salt solutions are selected, the crystallization point of the
specified-density fluid must be known and compared to the projected
temperature profiles expected during the well control pumping program
to ensure that the fluid temperature cannot fall below the
crystallization point.
Formation
damage concerns. Once the appropriate kill-weight fluid
density is calculated for the given well conditions, an assessment
should be made as to type and rheology of kill-weight fluid to be
selected. If formation damage and/or return permeability is not a
concern in the well control program, then a colloidal kill-weight mud
system can be considered. The mud system, which may be either water-or
oil-based, can be blended to the desired fluid density with suspended
solids to achieve the required kill-weight.
By design,
colloidal mud systems form a filter cake across a permeable formation,
essentially creating a barrier to fluid losses. Although these mud
systems are very effective kill-weight fluid candidates, the damage to
the formation, which typically accompanies their use, is undesirable.
If the
formation exposed to the wellbore during the kill program is expected
to be returned to production, the kill-weight fluid selection process
should include a review of fluids that offer minimal consequential
formation damage and high return permeability. Typically, these fluids
are in a class of liquids described as high-density brines, which
behave as clear-penetrating liquids when placed across permeable
formations. As a result, kill-weight fluid losses to the formation can
be expected when high-density brines are used.
The volume of
fluid loss depends upon the amount of excess annulus pressure applied,
either as back pressure from the surface choke program or from
frictional pressure losses developed within the annuli during the
circulation program. When considering the use of high-density brines
for kill-weight fluids, it is also important to determine their
chemical compatibility with formation fluids to ensure that no
secondary emulsions or adverse precipitation of solids will occur as a
result of the dissimilar fluid contact. Further, mitigation of
formation damage is more effective when the high-density,
clear-penetrating brines are filtered prior to circulation within the
wellbore.
Surface
fluid tankage requirements. The proposed kill-weight fluid
chemistry and rheology should be compared with the chemistry and
rheology of fluids available on site to determine whether the two
fluid systems are compatible. For example, if the typically pumped
treatment fluid is of a chemistry or rheology where blending to
achieve kill-weight density is not possible or desirable, then plans
must be made to mobilize additional tankage to transport and/or blend
a completely separate volume of kill-weight fluid. The assessment of
minimum tankage volume needed to prepare a kill-weight fluid
circulation program must include the internal volume capacity of the
workstring, internal volume capacity of all exposed completion
tubulars within the wellbore and the estimated volume of kill-weight
fluids lost to the exposed formation when performing the circulation
kill program.
Depending upon
the sophistication of the kill-weight fluid mixing program, it may be
desirable to batch-blend in 20- to 35-bbl volumes to accommodate
limited space availability on location. In high-density, clear brine
kill programs, brine is typically expensive and will most likely be
pre-mixed at the fluid supplier facility. As such, onsite space
accommodations for the tankage needed to transport the required volume
of kill-weight fluid must be addressed.
Further,
contingencies must be prepared for capture of the fluid volumes to be
circulated out of the wellbore. If it is not possible or desirable to
displace the existing wellbore fluids to the production system, then
additional tankage will be needed to capture the volume of
contaminated or displaced fluids from within the wellbore tubulars.
This volume must accommodate the internal capacity of exposed
completion tubulars within the wellbore and include additional fluid
volume gained in the form of influx occurring during the fluid
circulation program. Onsite space limitations for surface fluid
tankage must be addressed before equipment is dispatched to ensure
that the required fluid volumes can be provided to location before
operations commence.
Well
control choke pressure schedule. Once the circulation well
kill method is selected and operating parameters critical to proper
implementation are determined, the surface choke pressure schedule
must be prepared. This schedule is designed to impose a desired
surface pressure onto the wellbore annuli to ensure that a constant
bottomhole pressure (CBP) is maintained during the kill-weight fluid
circulation program.
For
conventional circulation kill programs, the total calculated volume of
kill fluid needed to fill the wellbore annuli is divided by ten, which
allows the user to prepare a volumetric displacement schedule in ten
equal stages. Each volume stage circulated into the wellbore
represents an increase in kill-weight fluid column height within the
annuli, yielding an increase in hydrostatic pressure acting on the
exposed formation interval.
Note that the
predicted MD for the top of each kill-weight fluid stage in the
wellbore annuli must be corrected to TVD measurements. Based on the
corrected vertical height of the kill-fluid / resident fluid
interface, the increases in hydrostatic pressure acting on the
formation must be compensated by a corresponding decrease in surface
choke pressure. From this wellbore annuli fill-up schedule, a
surface-choke-pressure adjustment schedule can be prepared wherein
uniform decreases in surface choke pressure are made for each stage of
kill-weight fluid pumped.
For well
configurations with minimal ID bore changes, this practice provides a
reasonably accurate means for predicting the choke pressure
adjustments for maintaining CBP with uniform stages pumped. However,
well control operations conducted concentric to existing completion
tubulars typically deal with multiple ID bore changes, making the
uniform ten-stage surface choke schedule format inappropriate for CBP
kill programs. With the variations in annuli geometry for multiple ID
bore completions, the fluid height attained within the annuli on a
pumped-stage basis does not yield the predicted hydrostatic pressure
increases, significantly altering the CBP well control program.
In the
following example, a concentric tubing fluid circulation kill program
is to be conducted within a well having 2-7/8-in. OD production tubing
(2.441-in. ID) set at a depth of 9,440 ft MD (9.440 ft TVD). Below the
packer setting depth is a segment of 7-in. OD (6.184-in. ID) casing,
with the completion interval top located at a depth of 10,000 ft MD
(10,000 ft TVD), Fig. 3. The estimated formation pressure for this
completion interval is 5,200 psig. Assuming a 1.25-in. OD coiled
tubing workstring is run within this wellbore, the proposed
circulation program requires 60 bbl of kill fluid to fill the casing
and tubing annulus from the top of the exposed completion interval to
the surface returns point in the riser. The casing annulus interval is
560 ft in height and requires approximately 20 bbl to fill. The
remaining 40 bbl are required to fill the 9,440 ft of production tube
annulus.
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Fig.
3. Assuming 1.25-in. OD coiled tubing is run into this
wellbore, the proposed circulation program requires 60 bbl of
kill fluid to fill casing / tubing annulus from the top of the
exposed completion interval to the surface returns point in
the riser. Casing annulus interval is 560 ft and requires
about 20 bbl to fill. Remaining 40 bbl are required to fill
the 9,440 ft of production tube annulus. |
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With a recorded
shut-in tubing pressure of 1,000 psig, the conventional
surface-choke-pressure schedule would be divided into ten equal
stages, with each stage comprised of a 6-bbl volume of kill fluid.
Following this program outline, the surface choke pressure schedule
would reduce the choke pressure by 100 psig per stage, Fig. 4.
However, due to the significant differences in fill-up volume between
the production tube and casing annuli for this example wellbore, this
schedule would create an underbalanced pressure condition early in the
kill program, causing formation fluid influx and compromising the well
control program.
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Fig.
4. With shut-in tubing pressure of 1,000 psig, the
conventional surface-choke-pressure schedule would be divided
into ten, 6-bbl kill fluid stages. However, due to significant
differences in fill-up volume between production tube and
casing annuli for this example, an underbalanced pressure
condition would be created early in the kill program. |
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Therefore, a
separate choke pressure schedule should be prepared for both the
production tube annulus and the casing annulus. A comparison of the
conventional and recommended surface choke pressure schedules for this
example is shown in Table 1 and illustrates how an underbalanced
condition of about 250 psig can be created if the conventional
surface-choke-pressure schedule is used. To ensure that the
surface-choke-pressure schedule properly accounts for the actual
increase in hydrostatic pressure resulting from the fill-up volume
stages, each change in annulus geometry should be evaluated separately
to determine the corrected bottomhole pressure.
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Table 1. Comparison of kill choke schedules; Standard Method vs.
Recommended Method |
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Stage |
Barrels |
Standard
kill,
psig |
CT kill,
psig |
DP per case,
psig |
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1 |
6 |
900 |
983 |
83 |
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|
2 |
12 |
800 |
966 |
166 |
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|
3 |
18 |
700 |
949 |
249 |
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4 |
24 |
600 |
813 |
213 |
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5 |
30 |
500 |
677 |
177 |
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6 |
36 |
400 |
541 |
141 |
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7 |
42 |
300 |
405 |
105 |
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8 |
48 |
200 |
269 |
69 |
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9 |
54 |
100 |
133 |
33 |
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10 |
60 |
0 |
0 |
0 |
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Bibliography
World Oils
Coiled Tubing Handbook, 3rd Edition, Gulf Publishing Co., Houston,
TX, 1998.
Sas-Jaworsky,
A., and Ali Ghalambor, "Considerations for Conducting Coiled
Tubing Well Control Operations to Minimize Formation Impairment,"
SPE Paper 58792, presented at 2000 SPE International Symposium on
Formation Damage Control, Lafayette, LA, February 2000.
Sas-Jaworsky,
A., "Practical Considerations for Enhancing Coiled Tubing Well
Control Operations," SPE Paper 60739, presented at the 2000
SPE/ICoTA Coiled Tubing Roundtable, Houston, TX, April 2000.
Well Control
School, Guide to Blowout Prevention, WCS First Edition, New
Orleans, LA, 2000.
Coming
installments:
Part 2
Practical application of through-tubing well control operations.
Part 3
Well control pumping options to minimize induced formation damage.
Part 4
Proper selection of coiled tubing surface and downhole well
control equipment.
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 degree 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
2 |
Part
3 |
Part
4 |
Part
5 |
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