U.S. patent application number 12/677719 was filed with the patent office on 2010-12-16 for method of using pressure signatures to predict injection well anomalies.
This patent application is currently assigned to M-I L.L.C.. Invention is credited to Francisco Fragachan, Kenneth G. Nolte, Adriana P. Ovalle, Talgat A. Shokanov.
Application Number | 20100314104 12/677719 |
Document ID | / |
Family ID | 40452407 |
Filed Date | 2010-12-16 |
United States Patent
Application |
20100314104 |
Kind Code |
A1 |
Shokanov; Talgat A. ; et
al. |
December 16, 2010 |
METHOD OF USING PRESSURE SIGNATURES TO PREDICT INJECTION WELL
ANOMALIES
Abstract
A method of designing a response to a fracture behavior of a
formation during re-injection of cuttings into a formation, the
method including obtaining a pressure signature for a time period,
interpreting the pressure signature for the time period to
determine a fracture behavior of the formation, determining a
solution based on the fracture behavior of the formation, and
implementing the solution is disclosed. A method of assessing a
subsurface risk of a cuttings re-injection operation, the method
including obtaining a pressure signature for a time period,
interpreting the pressure signature to determine a fracture
behavior of the formation, characterizing a risk associated with
the determined fracture behavior of the formation, and implementing
a solution based on the characterized risk is also disclosed.
Inventors: |
Shokanov; Talgat A.;
(Almaty, KZ) ; Nolte; Kenneth G.; (Tulsa, OK)
; Fragachan; Francisco; (Barcelona, ES) ; Ovalle;
Adriana P.; (Cypress, TX) |
Correspondence
Address: |
OSHA LIANG/MI
TWO HOUSTON CENTER, 909 FANNIN STREET, SUITE 3500
HOUSTON
TX
77010
US
|
Assignee: |
; M-I L.L.C.
Houston
TX
|
Family ID: |
40452407 |
Appl. No.: |
12/677719 |
Filed: |
September 3, 2008 |
PCT Filed: |
September 3, 2008 |
PCT NO: |
PCT/US08/75087 |
371 Date: |
August 24, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60972092 |
Sep 13, 2007 |
|
|
|
Current U.S.
Class: |
166/250.1 |
Current CPC
Class: |
E21B 49/008 20130101;
E21B 47/10 20130101; E21B 21/066 20130101; E21B 41/0057
20130101 |
Class at
Publication: |
166/250.1 |
International
Class: |
E21B 49/00 20060101
E21B049/00 |
Claims
1. A method of designing a response to a fracture behavior of a
formation during re-injection of cuttings into a formation, the
method comprising: obtaining a pressure signature for a time
period; interpreting the pressure signature for the time period to
determine a fracture behavior of the formation; determining a
solution based on the fracture behavior of the formation; and
implementing the solution.
2. The method of claim 1, wherein interpreting the pressure
signature comprises determining the pressure signature to be one of
the group consisting of normal pressure decline, wellbore storage
pressure decline, fracture storage pressure decline, decline
pressure rebound, and injection above overburden.
3. The method of claim 1, further comprising obtaining a second
pressure signature from a time period after implementing the
solution and determining if the solution affected the fracture
behavior.
4. The method of claim 1, further comprising characterizing a
subsurface risk of the fracture behavior.
5. The method of claim 1, wherein the determining the solution
comprises determining a cause of the fracture behavior.
6. The method of claim 1, further comprising generating a visual
representation of the pressure signature.
7. The method of claim 1, wherein the interpreting the pressure
signature comprises comparing the pressure signature to a known
pressure signature.
8. The method of claim 1, wherein the time period comprises a
fracture closure period.
9. The method of claim 1, wherein the time period comprises a post
shut-in interval.
10. The method of claim 1, wherein the solution comprises injecting
sea water downhole.
11. The method of claim 1, wherein the solution comprises
continuing the cuttings re-injection operation.
12. A method of assessing a subsurface risk of a cuttings
re-injection operation, the method comprising: obtaining a pressure
signature for a time period; interpreting the pressure signature to
determine a fracture behavior of the formation; characterizing a
risk associated with the determined fracture behavior of the
formation; and implementing a solution based on the characterized
risk.
13. The method of claim 12, wherein the interpreting the pressure
signature comprises comparing the pressure signature to a known
pressure signature.
14. The method of claim 13, wherein the known pressure signature
comprises at least one of a group consisting of normal pressure
decline, wellbore storage pressure decline, fracture storage
pressure decline, decline pressure rebound, and injection above
overburden.
15. The method of claim 12, wherein the characterizing a risk
associated with the determined fracture behavior of the formation
comprises determining the possibility of the determined fracture
behavior affecting a planned well.
16. The method of claim 12, wherein the characterizing a risk
associated with the determined fracture behavior of the formation
comprises determining the well disposal capacity based on the
fracture behavior.
17. The method of claim 12, wherein the solution comprises
injecting sea water downhole.
18. The method of claim 12, wherein the solution comprises
continuing the cuttings re-injection operation.
Description
BACKGROUND
[0001] 1. Field of the Invention
[0002] Embodiments disclosed herein generally relate to methods of
determining the fracture behavior of a disposal formation during a
CRI operation.
[0003] 2. Background Art
[0004] In the drilling of wells, a drill bit is used to dig many
thousands of feet into the earth's crust. Oil rigs typically employ
a derrick that extends above the well drilling platform. The
derrick supports joint after joint of drill pipe connected
end-to-end during the drilling operation. As the drill bit is
pushed further into the earth, additional pipe joints are added to
the ever lengthening "string" or "drill string". Therefore, the
drill string includes a plurality of joints of pipe.
[0005] Fluid "drilling mud" is pumped from the well drilling
platform, through the drill string, and to a drill bit supported at
the lower or distal end of the drill string. The drilling mud
lubricates the drill bit and carries away well cuttings generated
by the drill bit as it digs deeper. The cuttings are carried in a
return flow stream of drilling mud through the well annulus and
back to the well drilling platform at the earth's surface. When the
drilling mud reaches the platform, it is contaminated with small
pieces of shale and rock that are known in the industry as well
cuttings or drill cuttings. Once the drill cuttings, drilling mud,
and other waste reach the platform, a "shale shaker" is typically
used to remove the drilling mud from the drill cuttings so that the
drilling mud may be reused. The remaining drill cuttings, waste,
and residual drilling mud are then transferred to a holding trough
for disposal. In some situations, for example with specific types
of drilling mud, the drilling mud may not be reused and it must be
disposed. Typically, the non-recycled drilling mud is disposed of
separate from the drill cuttings and other waste by transporting
the drilling mud via a vessel to a disposal site.
[0006] The disposal of the drill cuttings and drilling mud is a
complex environmental problem. Drill cuttings contain not only the
residual drilling mud product that would contaminate the
surrounding environment, but may also contain oil and other waste
that is particularly hazardous to the environment, especially when
drilling in a marine environment.
[0007] One method of disposing of oily-contaminated cuttings is to
re-inject the cuttings into the formation using a cuttings
re-injection (CRI) operation. The basic steps in the process
include the identification of an appropriate stratum or formation
for the injection; preparing an appropriate injection well;
formulation of the slurry, which includes considering such factors
as weight, solids content, pH, gels, etc.; performing the injection
operations, which includes determining and monitoring pump rates
such as volume per unit time and pressure; and capping the
well.
[0008] Accordingly, there exists a need for methods of determining
the fracture behavior of a disposal formation during a CRI
operation.
SUMMARY OF INVENTION
[0009] In one aspect, embodiments disclosed herein relate to a
method of designing a response to a fracture behavior of a
formation during re-injection of cuttings into a formation, the
method including obtaining a pressure signature for a time period,
interpreting the pressure signature for the time period to
determine a fracture behavior of the formation, determining a
solution based on the fracture behavior of the formation, and
implementing the solution.
[0010] In another aspect, embodiments disclosed herein relate to a
method of assessing a subsurface risk of a cuttings re-injection
operation, the method including obtaining a pressure signature for
a time period, interpreting the pressure signature to determine a
fracture behavior of the formation, characterizing a risk
associated with the determined fracture behavior of the formation,
and implementing a solution based on the characterized risk.
[0011] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0012] FIG. 1 shows a method of pressure signature interpretation
and anomaly identification.
[0013] FIG. 2 shows a normal pressure signature for a CRT operation
immediately after shut-in.
[0014] FIG. 3 shows a pressure signature representing a wellbore
storage pressure decline behavior.
[0015] FIG. 4 shows a pressure signature representing a fracture
storage pressure decline behavior.
[0016] FIG. 5 shows a pressure signature representing a decline
pressure rebound.
[0017] FIG. 6 shows a pressure signature on a log plot representing
injection above overburden.
DETAILED DESCRIPTION
[0018] In one aspect, embodiments disclosed herein relate to
interpreting pressure behavior of CRI operations. In another
aspect, embodiments disclosed herein relate to assessing potential
risk and impact on a subsurface drilling system and surrounding
formation.
[0019] Batch processing of slurry (i.e., injecting conditioned
slurry into the disposal formation and then waiting for a period of
time after the injection) allows fractures to mechanically close
and, to a certain extent, dissipates the build-up of pressure in
the disposal formation. However, the pressure in the disposal
formation typically increases due to the presence of the injected
solids (i.e., the solids present in the drill cuttings slurry).
[0020] The slurry to be injected should be maintained within
calculated parameters to reduce the chances of fracture plugging.
To monitor the slurry, rheological parameters are often checked on
a periodic basis to ensure that the slurry exhibits predetermined
characteristics. For example, some systems incorporate a continual
measurement of slurry viscosity and density prior to injection.
[0021] Release of hazardous waste into the environment must be
avoided and waste containment must be assured to satisfy stringent
governmental regulations. Important containment factors considered
during the course of the operations include the following: the
location of the injected waste and the mechanisms for storage; the
capacity of an injection wellbore or annulus; whether injection
should continue in the current zone or in a different zone; whether
another disposal wellbore should be drilled; the required operating
parameters necessary for proper waste containment; and the
operational slurry design parameters necessary for solids
suspension during slurry transport.
[0022] Modeling of CRI operations and prediction of disposed waste
extent are beneficial to address these containment factors and to
ensure the safe and lawful containment of the disposed waste.
Modeling and prediction of fracturing is also beneficial to study
CRI operation impact on future drilling, such as the required well
spacing, formation pressure increase, etc. A thorough understanding
of storage mechanisms in CRI operations is key for predicting the
possible extent of the injected conditioned slurry and for
predicting the disposal capacity of an injection well. As used
herein, storage mechanisms may refer to modes or methods in which
slurry is stored in a formation, including, for example, methods of
injection into a formation, methods of injection into a fracture,
fracture growth, and changes in fracture geometry.
[0023] Once the required shut-in time for fracture closure is
computed from the fracturing simulation, a subsequent batch
injection may cause reopening of an existing fracture and may
create a secondary branched fracture away from the near-wellbore
area. This situation may be determined from local stress, pore
pressure changes from previous injections, and formation
characteristics. The location and orientation of the branched
fracture may also depend on stress anisotropy. For example, if a
strong stress anisotropy is present, then the fractures are closely
spaced, however if no stress anisotropy exits, the fractures are
widespread. How these fractures are spaced and the changes in shape
and extent during the injection history may be an important factor
in determining the disposal capacity of a disposal well.
[0024] Modeling and simulating CRI operations and fracturing of the
formation typically do not provide instantaneous or real-time
results during the CRI operations. Further, models and simulations
of the CRI operation do not reveal causes for the fracture behavior
of the formation. Embodiments disclosed herein, however, provide a
method of observing, identifying, and interpreting common pressure
signatures observed during CRI operations. Further, embodiments
disclosed herein may provide a method for designing a response to a
fracture behavior of a formation during CRI operations.
[0025] To increase safety during CRI operations, the pressure
response during injection and post shut-in pressure decline periods
may be continuously monitored. Readily implemented injection
pressure monitoring coupled with in-depth pressure analysis may
assist in diagnosing the fracture behavior during the pumping and
shut-in periods, and in estimating key fracture and formation
parameters. In addition, continuous fracture diagnostics may assist
in tracking long-term progression of mechanical parameters, for
example, fracture length, width, and direction, and assessing an
overall impact posed by injected waste on the disposal and
surrounding formations.
[0026] A primary objective of CRI is attaining an environmentally
safe and trouble-free subsurface disposal of the drilling waste by
means of intermitted batch injections. Accordingly, the importance
of pressure analysis as an effective tool for subsurface risks
identification and characterization is essential. In-depth
interpretation of varied pressure signatures repeatedly observed
during cycle injections may be used to reveal and understand the
nature of the subsurface risks, characterize possible causes, and
comprehensively assess future impact on the subsurface system.
Proper and timely pressure signature interpretation may help in
securing seamless CRI operation, extend the life of the injection
well, and maximize well disposal capacity. Conversely, a lack of
subsurface waste injection experience combined with neglect of
distinct pressure signatures may potentially lead to unexpected
loss of injectivity, which may increase the cost of well
re-completion or result in extra injection well drilling.
[0027] Methods of interpreting pressure signatures are presented
below. Interpretations of the five most common pressure signatures
frequently observed and identified during injection from globally
varied CRI projects are presented below. The use of pressure
signature interpretation may provide a better understanding of
non-ideal pressure behavior observed in CRI operations, may assess
potential risk and impact on the subsurface system, and may provide
a solution or action based on the determined fracture behavior of
the formation.
[0028] Method of Interpreting Pressure Signatures
[0029] Pressure signatures from CRI operations may be interpreted
to better understand and address non-ideal pressure behavior
observed in CRI operations. Additionally, the operator may be able
to assess potential risk and impact on the subsurface system caused
by the CRI operations. In one embodiment, pressure signatures may
include a graphical representation of a plurality of pressure
measurements taken over a period of time. Such graphical
representations of pressure signatures are shown in FIGS. 2-6. In
other embodiments, pressure signatures may include a plurality of
pressure measurements taken over a period of time and displayed in
tabular form. One of ordinary skill in the art will appreciate that
a pressure signature may include any output known in the art for
conveying a plurality of pressure measurements taken over a period
of time.
[0030] Referring to FIG. 1, in one embodiment, a pressure signature
may be determined for a pre-selected time period of CRI operation,
shown at 120. The pressure signature may be determined by any means
known in the art and may be taken at varying intervals during, for
example, injection, post shut-in, fracture closure, or continuously
during CRI operations.
[0031] The pressure signatures obtained may then be interpreted for
each time period to determine a fracture behavior of the formation,
shown at 122. In one embodiment, the pressure signatures may be
compared to pressure signatures identified as representing a
subsurface condition or fracture behavior of the formation, as
described below. For example, a pressure signature obtained
immediately after shut-in may include a substantially straight line
on a pressure decline. Upon comparing the obtained pressure
signature to an identified pressure signature, the operator may
determine that the wellbore storage pressure decline indicates that
fluid communication between the wellbore and fracture has been
restricted (discussed in more detail below with respect to FIG.
3).
[0032] Based on the fracture behavior or subsurface behavior
interpreted from the pressure signature 122, a solution may be
determined 124 and subsequently implemented 126. For example, if
the operator determines that a restriction between the wellbore and
the formation has occurred, seawater may be injected downhole to
prevent solid settling and/or to relieve stress in the formation,
thereby reducing or removing the restriction.
[0033] In one embodiment, the subsurface risk associated with the
fracture behavior may be characterized in a range of low to high
risk or on a number scale representing a low to high range of risk.
For example, in one embodiment, a pressure signature may be
interpreted and a fracture behavior of the formation determined.
The operator may then classify or characterize the risk of such
fracture behavior. For example, if the operator determines that a
fracture includes a horizontal component, the operator may assess
the risk of the horizontal component of the fracture intersecting a
trajectory of a planned well. In this example, the operator may
characterize the fracture behavior as a high risk, because it may
frustrate drilling of a planned well. In other embodiments, the
pressure signature may be interpreted as representing a normal
pressure decline. As such, the operator may characterize the
fracture behavior as a low risk. Thus, the solution determined
based on the fracture behavior of the formation may include taking
no action or continuing the CRI operation. In other embodiments,
the subsurface risk associated with the fracture behavior may
include determining, for example, the well disposal capacity
associated with the fracture behavior, expected pressure changes
due to the fracture behavior, and expected geometry changes of the
fracture.
[0034] Normal Pressure Decline
[0035] Normal pressure (or conventional pressure decline) is
frequently observed during post shut-in periods. FIG. 2 shows a
pressure signature that represents an example of a normal pressure
decline. A normal pressure is determined by the fracture closure
and formation transient response, and indicates open (or
unrestricted) communication between the fracture and the wellbore.
Generally, two distinct periods are distinguished during the
pressure decline: fracture closure period and transient formation
period.
[0036] Fracture behavior during the fracture closure period is
governed by fluid-loss characteristics (i.e., fluid volume lost
from the fracture to the formation) and the material balance
relation. The pressure decline during fracture closure period
reflects both fracture length and height change. The fracture
penetration initially increases before eventually receding back
toward the wellbore. Initial fracture extension generally occurs
because of redistribution of stored slurry volume from a large
width of the fracture near the wellbore to a fracture tip region.
Simultaneously, the height recedes from any higher stress barriers
because of pressure reduction in the fracture (i.e., net pressure).
By looking at the shape of the pressure decline of the pressure
signature, a fracture height growth into higher stress barriers
(e.g., containment zone) may be identified. For example, a concave
downward pressure decline signature indicates the fracture height
growth does not reach a higher stress fracture containment zone. In
contrast, a concave upward pressure decline signature indicates
significant fracture height growth into the higher stress barrier
zones.
[0037] In accordance with embodiments of the present disclosure, a
subsurface event may be determined from such pressure decline
signatures. For example, a concave upward pressure decline
signature may signify a fluid redistribution in a fracture from
higher stress zones (due to height recession) into a main fracture
body. A redistribution of fluid in a fracture from a higher stress
zone into a main fracture body typically occurs when the net
pressure becomes equal to approximately 0.4 times a stress
difference between injection and a higher stress barrier zone.
Fluid efficiency and a fluid leak-off coefficient may be estimated
from the pressure decline signature by utilizing a specialized
O-function of time, commonly referred as the O-plot. (See, for
example, U.S. Pat. No. 6,076,046, issued to Vasudevan, incorporated
by reference herein.) However, the G-slope application has the same
uncertainties as those observed with the interpretation of
conventional well test data.
[0038] The pressure decline during a transient formation period, or
the pressure following fracture closure, relates to an injection
formation response. The pressure response during this transient
formation period becomes less dependent on the mechanical response
of an open fracture and more dependent on the transient pressure
response within the injection formation. The character of the
transient formation period pressure decline is determined
primarily, if not entirely, by the response of the injection
formation disturbed by the fluid leak-off process (migration of the
fluid into the fracture face). During this transient formation
period, the reservoir may initially exhibit formation linear flow
followed by transitional behavior and finally long-term
pseudo-radial flow. The pressure decline during the transient
formation period provides information that is traditionally
determined by a standard well test (i.e., transmissibility and
formation pressure), and it completes a chain of fracture pressure
analyses that provides a complete set of data required for
developing a unique characterization of an effect from the
fracturing process.
[0039] A normal pressure signature for a CRI operation typically
does not represent any potential risks for the subsurface system
and may be considered as a safe pressure signature. A normal
pressure signature may be used to evaluate the fracture behavior
during closure and to estimate main fracture and formation
parameters. Thus, in accordance with embodiments of the present
disclosure, a pressure signature during a CRI operation that,
similar to FIG. 2, represents a normal pressure decline may
indicate to an operator that the fracture behavior of the formation
does not suggest a risk for the subsurface system. Therefore, the
operator may continue the CRI operation without taking any further
action.
[0040] Wellbore Storage Pressure Decline
[0041] FIG. 3 shows a pressure signature for a CRI operation
immediately after shut-in. A wellbore storage pressure decline
signature indicates a restriction between the wellbore and
formation. The restriction may be caused by sealing between the
wellbore and formation by, for example, viscous fluid from a
previous injection or from solids fall-off and settling. The
restriction may also be caused by a mechanical restriction
accidentally induced in the injection point by, for example,
cement. The wellbore storage pressure response may also be a result
of fluid compression or expansion in a confined volume. The
formation sealing prevents adequate fluid communication between the
fracture and the wellbore, and creates confined volume within the
wellbore. As shown in FIG. 3, the duration of the wellbore storage
pressure decline period depends on the severity of artificial
restriction as well as wellbore fluid compressibility, and may be
clearly characterized by the straight line, indicated at 302, on
the pressure decline occurring immediately after shut-in. The
pressure decline during this period no longer represents fracture
response and fracture parameters cannot be determined.
[0042] In most cases, a wellbore storage pressure signature
revealed immediately after shut-in, represents a warning signal of
an artificially induced restriction in the injection point. Due to
potential sealing of the injection interval, the wellbore storage
pressure behavior observed immediately after shut-in represents a
higher risk for potential well plugging. The risks for potential
well plugging worsens when particle settling is experienced during
an injection suspension period. Considering that well plugging
causes most failures in CRI projects, any wellbore storage pressure
behavior, as well as a root cause for the partial sealing of the
injection interval, observed immediately after shut-in must be
closely monitored, evaluated, and thoroughly investigated.
[0043] Referring still to FIG. 3, a wellbore storage pressure
response observed immediately after shut-in during a CRI project
annular injection while cementing a 95/8-inch casing is shown. In
this example, the actual cement level was higher than initially
designed. Consequently, the cement bridged part of an open-hole
injection interval and induced artificial restriction in the
injection point. This is reflected immediately in the pressure
signature by the wellbore storage pressure behavior (i.e., straight
line portion indicated at 302) after shut-in and later confirmed by
a cement evaluation log.
[0044] Thus, in accordance with embodiments of the present
disclosure, a pressure signature during a CRI operation that,
similar to FIG. 3, represents a wellbore storage post shut-in
pressure decline may indicate to the operator that fluid
communication between the wellbore and the fracture has been
restricted. In one embodiment, the operator may, therefore, perform
seawater injection to prevent solid settling and/or to relieve
stress in the formation. Alternatively, acid may be pumped downhole
to dissolve the mechanical restriction and restore normal
communication between the wellbore and the fracture. Overall, this
type of the pressure signature, as shown in FIG. 3, represents a
high risk of the well or fracture plugging; hence, the pressure
signatures need to be closely monitored and corrective action
promptly implemented.
[0045] Fracture Storage Pressure Decline
[0046] Referring now to FIG. 4, a pressure signature representing a
fracture storage pressure decline is shown. A fracture storage
pressure signature generally exhibits a linear relation between
pressure and time (i.e., a straight line portion on the pressure
decline indicated at 404) during a post fracture closure period.
Fracture storage pressure decline typically results from the
pressure bouncing, shown at 406, within the confined fracture
boundary after closure. The fracture boundary confinement may
result from a filter cake at the fracture face created by previous
injections (e.g., residual polymers and solid particles) or damage
to the fracture face. Similar fracture confinement may also be
observed during tip screen-out (TSO) (i.e., when high
concentrations of sand or proppant reach the tip of the fracture
and halt further fracture extension), when fluid-loss induces
insufficient fracture width, or when dehydration causes the solids
slurry to bridge at the tip of the fracture.
[0047] During the fracture storage period, the pressure behavior is
dominated by the fluid storage in the fracture, assuming that the
wellbore storage has a minor effect on overall storage response.
The fracture storage pressure mainly occurs due to fluid
compression or expansion in confined fracture volume, where the
fracture may effectively transmit the pressure and has higher
permeability in comparison to the injected formation. The fracture
storage pressure is usually observed after the fracture
mechanically closes on the cutting solids, thereby allowing fluid
and pressure to redistribute inside the fracture. Factors affecting
fracture storage duration may include permeability and pressure
contrast between the fracture and injected formation, and severity
of the damage originated at the fracture face.
[0048] In accordance with embodiments of the present disclosure, a
pressure signature during a CRI operation that, similar to FIG. 4,
represents a fracture storage pressure decline may indicate to the
operator that the fracture face may be damaged, thereby causing
fracture confinement. In one embodiment, the operator may,
therefore, re-assess the fluid leak-off from the fracture to the
formation using a G-function plot, and evaluate the fracture
confinement by performing additional fracture simulation with
updated fluid leak-off and main fracture parameters (e.g., fracture
closure pressure).
[0049] Decline Pressure Rebound
[0050] Referring now to FIG. 5, a pressure signature representing a
decline pressure rebound is shown. In the embodiment shown, a
surface pressure re-bound, indicated at 508, has been observed
during post shut-in pressure decline, when injections were
suspended for a long period. Simultaneously drilling or production
activity in the injection well during a CRI operation may increase
the amplitude of a pressure re-bound. The pressure decline
initially drops below the fracture closure pressure and continues
declining until wellbore fluid starts to heat up, thereby affecting
the hydrostatic pressure in the wellbore. The wellbore fluid may
heat up due to heat generated during drilling and/or oil
production. As the temperature of wellbore fluid increases, the
hydrostatic head decreases, thereby causing an increase in surface
pressure (i.e., a pressure re-bound effect).
[0051] The amplitude of the pressure increase during a re-bound
period is proportional to the increase of fluid temperature in the
wellbore. Although the pressure increases during the re-bound
period, the fracture may not be re-initiated, because of the
thermo-elastic impact on the formation. In other words, the
temperature variation in the wellbore changes the state of stress,
especially in a near-wellbore area. Typically, formation heat-up
during a suspended period induces an additional stress component in
the horizontal plane, while formation heat-up in the near-wellbore
area increases the normal stress. Thus, wellbore fluid heat-up may
lead to a higher breakdown pressure required to overcome additional
thermal stress in the near wellbore area to initiate the
fracture.
[0052] The risk associated with excessive wellbore fluid heat-up is
primarily related to higher injection pressure on surface and
inability to inject within pre-defined surface pressure limits.
Thus, in one embodiment, the near-wellbore thermo-elastic stress
component may be reduced by maintaining regular seawater injections
during extended suspension periods, which effectively cools the
static wellbore fluid. As a result, less pressure is required to
initiate the fracture after a suspended period and the surface
injection pressure may be maintained below maximum limits.
[0053] Injection Above Overburden
[0054] Referring now to FIG. 6, a pressure signature representing
injection above overburden is shown on a log plot. As used herein,
overburden refers to the formation or rock overlying an area or
point of interest in the subsurface. If the injection pressure is
less than the overburden stress, a fracture may propagate only in
the vertical plane. However, in a situation when injection occurs
in conditions of shallow depth or in formations in tectonically
active thrusting environments, the overburden stress may be a
minimum principal stress. In such shallow depth conditions, the
fracture may propagate in both the vertical and horizontal planes.
This geometry is called a T-shape fracture and occurs when an
injection pressure is slightly larger than the overburden
stress.
[0055] The pressure response during such a period where the
injection pressure is slightly larger than the overburden stress
provides a diagnostic basis for determining whether the fracture
plane is entirely vertical or includes a horizontal component as
well. The horizontal component (propagation in a horizontal
direction) occurs when the fracture pressure is substantially
constant and approximately equal to or above the overburden stress
of the formation, as shown in FIG. 6. After the injection pressure
exceeds overburden, the penetration of the vertical component
becomes less efficient, because the propagating horizontal
component prevails.
[0056] The horizontal fracture component increases the area
available for fluid loss, decreases fluid efficiency, and limits
the fracture width. Excessive fluid loss in the horizontal
component and limited fracture width may lead to premature
screen-out or fracture plugging during injection. Horizontal
fractures may provide extended coverage area with larger disposal
capacity. However, due to the risk associated with a horizontal
fracture intersecting trajectories of planned offset drilling
wells, such horizontal fractures may need to be thoroughly
evaluated. The magnitude of the overburden stress may be estimated
from density logs and compared with the magnitude of the injection
pressure as part of the pressure analysis.
[0057] In accordance with embodiments of the present disclosure, a
pressure signature during a CRI operation that, similar to FIG. 6,
represents injection above overburden may be used to determine the
geometry of the fracture in the formation. The operator may
determine a solution to reduce excessive fluid loss and/or increase
fracture width to prevent premature screen-out or fracture plugging
during injection. If the pressure signature indicates that the
fracture may include a horizontal component, then the operator may,
for example, re-design trajectories of future wells to avoid
intersecting the horizontal component of the fracture.
Additionally, the operator may perform detail pressure signature
interpretation on a regular basis to avoid premature screen-out,
particularly in the near-wellbore area or at an intersection
between vertical and horizontal components of the fracture.
[0058] Advantageously, embodiments disclosed herein provide a
method of determining a fracture behavior of a formation during a
CRI operation. Further, embodiments disclosed herein may provide a
method of optimizing well disposal capacity by allowing an operator
to determine fracture behavior or formation and subsurface events
during CRI operations. In yet other embodiments disclosed herein, a
method for determining a solution and implementing a solution based
on a fracture behavior determined by interpreting a pressure
signature is provided.
[0059] Advantageously, embodiments disclosed herein may provide
operators a method of addressing non-ideal pressure behavior during
CRI operations and a method of assessing potential risks and
impacts of the CRI operation on subsurface systems and
formation.
[0060] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
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