U.S. patent application number 17/626942 was filed with the patent office on 2022-08-18 for system and method for dual tubing well design and analysis cross-reference to related applications.
This patent application is currently assigned to LANDMARK GRAPHICS CORPORATION. The applicant listed for this patent is LANDMARK GRAPHICS CORPORATION. Invention is credited to Adolfo Gonzales, Jun JIANG, Yongfeng KANG, Zhengchun Liu, Robello SAMUEL.
Application Number | 20220259948 17/626942 |
Document ID | / |
Family ID | 1000006360784 |
Filed Date | 2022-08-18 |
United States Patent
Application |
20220259948 |
Kind Code |
A1 |
Liu; Zhengchun ; et
al. |
August 18, 2022 |
SYSTEM AND METHOD FOR DUAL TUBING WELL DESIGN AND ANALYSIS
CROSS-REFERENCE TO RELATED APPLICATIONS
Abstract
Methods and systems for analyzing a well system design including
determining a volume change of trapped annular regions based on a
plurality of initial temperatures and a plurality of final
temperatures and an initial pressure. Analyzing the trapped annular
regions to determine an enclosure volume change, a fluid expansion
volume, and an annular pressure buildup for a safe well system and
generating a graphical representation of the bounds of the safe
well system envelop.
Inventors: |
Liu; Zhengchun; (Sugar Land,
TX) ; KANG; Yongfeng; (Katy, TX) ; Gonzales;
Adolfo; (Houston, TX) ; SAMUEL; Robello;
(Cypress, TX) ; JIANG; Jun; (Austin, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
LANDMARK GRAPHICS CORPORATION |
Houston |
TX |
US |
|
|
Assignee: |
LANDMARK GRAPHICS
CORPORATION
Houston
TX
|
Family ID: |
1000006360784 |
Appl. No.: |
17/626942 |
Filed: |
August 6, 2020 |
PCT Filed: |
August 6, 2020 |
PCT NO: |
PCT/US2020/045203 |
371 Date: |
January 13, 2022 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
62891227 |
Aug 23, 2019 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 41/00 20130101;
E21B 17/00 20130101; E21B 2200/20 20200501; E21B 43/00
20130101 |
International
Class: |
E21B 41/00 20060101
E21B041/00; E21B 17/00 20060101 E21B017/00; E21B 43/00 20060101
E21B043/00 |
Claims
1. A method for designing a well system envelop, the method
comprising: creating an initial design for a well system including
two or more tubing strings disposed within a well, the well system
including one or more trapped annular regions therein, each of the
one or more trapped annular regions including an enclosure;
determining a plurality of initial temperatures, a plurality of
final temperatures, and an initial pressure for each of the one or
more trapped annular regions; estimating a final pressure for each
of the one or more trapped annular regions; analyzing each of the
one or more trapped annular regions; and generating a wellbore
system envelop based at least in part on the analysis of each of
the one or more trapped annular regions.
2. The method of claim 1, wherein analyzing the one or more trapped
annular regions further comprises: selecting a first trapped region
from the one or more trapped annular regions; calculating an
enclosure volume change for the first trapped region; and
calculating an annular fluid expansion (AFE) of a well fluid
contained within the enclosure of the first trapped region, the AFE
corresponding to a fluid volume change caused by a temperature
change.
3. The method of claim 2, wherein analyzing the one or more trapped
annular regions further comprises determining an annular pressure
buildup (APB) corresponding to the first trapped region, wherein
when the enclosure volume change for the first trapped region is
balanced with the AFE for the first trapped region.
4. The method of claim 3, further comprising calculating a
plurality of APBs corresponding to each of the plurality of initial
temperatures and the plurality of final temperatures.
5. The method of claim 4, wherein when the well system further
includes at least two casings the enclosure of the one or more
trapped annular regions includes one or more casing enclosures
between two casings, one or more casing and tubing enclosures
between a casing and a tubing string, and one or more tubing
enclosures between two tubing strings.
6. The method of claim 4, further comprising calculating a
respective enclosure volume change, a plurality of respective AFEs,
and a plurality of respective APBs for each of the remaining one or
more trapped annular regions.
7. The method of claim 6, further comprising iterating the
calculations of the plurality of respective APBs for each of the
one or more trapped annular regions assuming a non-rigid
enclosure.
8. The method of claim 7, further comprising determining whether a
global pressure of the well system is balanced for each of the one
or more trapped annular regions within the well system based on the
non-rigid enclosures.
9. The method of claim 8, further comprising: generating a
graphical representation of the of the wellbore system envelop
showing a safe design limit, and transmitting the graphical
representation to an output device.
10. The method of claim 1, wherein the plurality of initial
temperatures, the initial pressure, and the plurality of final
temperatures for each of the one or more trapped annular regions
are determined using calculations and/or simulation.
11. A non-transitory computer-readable storage medium storing
computer-executable instructions which, when executed by one or
more processors, cause the one or more processors to: create
initial design for a well system including two or more tubing
strings disposed within a well, the well system including one or
more trapped annular regions therein, each of the one or more
trapped annular regions including an enclosure; determine a
plurality of initial temperatures, a plurality of final
temperatures, and an initial pressure for each of the one or more
trapped annular regions; estimate a final pressure for each of the
one or more trapped annular regions; analyze each of the one or
more trapped annular regions; and generate a wellbore system
envelop based at least in part on the analysis of each of the one
or more trapped annular regions.
12. The non-transitory computer-readable storage medium of claim
11, wherein the instructions further cause the processor to: select
a first trapped region from the one or more trapped annular
regions; calculate an enclosure volume change for the first trapped
region; and calculate an annular fluid expansion (AFE) of a well
fluid contained within the enclosure of the first trapped region,
the AFE corresponding to a fluid volume change caused by a
temperature change.
13. The non-transitory computer-readable storage medium of claim
12, wherein the instructions further cause the processor to:
determine an annular pressure buildup (APB) corresponding to the
first trapped region, wherein the enclosure volume change for the
first trapped region is balanced with the AFE for the first trapped
region.
14. The non-transitory computer-readable storage medium of claim
13, wherein the instructions further cause the processor to:
calculate a plurality of APBs corresponding to each of the
plurality of initial temperatures and the plurality of final
temperatures.
15. The non-transitory computer-readable storage medium of claim
14, wherein the instructions further cause the processor to:
calculate a respective enclosure volume change, a plurality of
respective AFEs, and a plurality of respective APBs for each of the
remaining one or more trapped annular regions.
16. The non-transitory computer-readable storage medium of claim
15, wherein the instructions further cause the processor to:
iteratively calculate a plurality of respective APBs for each of
the one or more trapped annular regions assuming a non-rigid
enclosure.
17. The non-transitory computer-readable storage medium of claim
16, wherein the instructions further cause the processor to:
determine whether a global pressure of the well system is balanced
for each of the one or more trapped annular regions within the well
system based on the non-rigid enclosures.
18. The non-transitory computer-readable storage medium of claim
17, wherein when the well system is balanced the instructions
further cause the processor to: generate a graphical representation
of the well system envelop showing a safe design limit; and display
the well system envelop and the safe design limit on an output
device communicatively coupled with the one or more processors.
19. A system comprising: a well system including a wellbore having
at least two tubing strings and at least one casing disposed
therein, the well system including a plurality of trapped annular
regions, each of the plurality of trapped annular regions being a
non-rigid enclosure; one or more processors coupled with an input
device; and at least one non-transitory computer-readable storage
medium storing instructions which, when executed by the one or more
processors, cause the one or more processors to: receive a
plurality of initial temperatures, an initial pressure, and a
plurality of final temperatures corresponding to each of the
plurality of trapped annular regions from one or more sensors
located within the wellbore of the well system; estimate a final
pressure for each of the one or more trapped annular regions;
analyze each of the one or more trapped annular regions; and
generate an integrity report for the well system, wherein the
integrity report is based at least in part on the analysis of each
of the plurality of trapped annular regions.
20. The system of claim 19, wherein the integrity report includes a
temperature range and a pressure range at which the well system
will fail.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional Patent
Application 62/891,227, which was filed in the U.S. Patent and
Trademark Office on Aug. 23, 2019, which is incorporated herein by
reference in their entirely for all purposes.
TECHNICAL FIELD
[0002] The present disclosure generally relates to a system and
method for providing design considerations for High-Pressure and
High-Temperature (HPHT) subterranean oil and gas wells. In
particular, the present disclosure relates to systems and methods
for the design and analysis of dual tubing wellbore
configurations.
BACKGROUND
[0003] Wellbores are drilled into the earth for a variety of
purposes including tapping into hydrocarbon bearing formations to
extract the hydrocarbons for use as fuel, lubricants, chemical
production, and other purposes. The oil and gas industry typically
drill wellbores through multiple subterranean formations, thereby
resulting in the establishment of multiple production zones at
various locations along the length of the wellbore. As the tubing
extends throughout the wellbore, it can encounter several turns
and/or changes in pressure. Such pressure can build up in the
tubing and the annulus of the well can cause equipment to
rupture.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] In order to describe the manner in which the above-recited
and other advantages and features of the disclosure can be
obtained, a more particular description of the principles briefly
described above will be rendered by reference to specific
embodiments thereof which are illustrated in the appended drawings.
Understanding that these drawings depict only exemplary embodiments
of the disclosure and are not therefore to be considered to be
limiting of its scope, the principles herein are described and
explained with additional specificity and detail through the use of
the accompanying drawings in which:
[0005] FIG. 1 is a schematic diagram illustrating an exemplary well
system which can employ the methods and systems disclosed herein,
in accordance with the present disclosure;
[0006] FIG. 2 is a diagram illustrating a subsurface well having
multiple tubing strings and casings disposed therein, in accordance
with the present disclosure;
[0007] FIG. 3A is a flow chart exemplifying the AFE/APB analysis
method, in accordance with the present disclosure;
[0008] FIG. 3B is a second half of a flow chart exemplifying the
AFE/APB analysis method, in accordance with the present
disclosure;
[0009] FIG. 4 illustrates a design limit envelop for a particular
well structure, in accordance with the present disclosure;
[0010] FIG. 5A is an illustration depicting a conventional system
bus computing system architecture capable of performing methods in
accordance with the present disclosure;
[0011] FIG. 5B is an illustration depicting a computer system
having a chipset architecture capable of performing methods in
accordance with; and
[0012] FIGS. 6A-C are diagrammatic representations of information
associated with an Annulus Pressure Buildup scenario in a steam
operation in a dual tubing well configuration.
DETAILED DESCRIPTION
[0013] It will be appreciated that for simplicity and clarity of
illustration, where appropriate, reference numerals have been
repeated among the different figures to indicate corresponding or
analogous elements. In addition, numerous specific details are set
forth in order to provide a thorough understanding of the examples
described herein. However, it will be understood by those of
ordinary skill in the art that the examples described herein can be
practiced without these specific details. In other instances,
methods, procedures, and components have not been described in
detail so as not to obscure the related relevant feature being
described. Also, the description is not to be considered as
limiting the scope of the embodiments described herein. The
drawings are not necessarily to scale and the proportions of
certain parts may be exaggerated to better illustrate details and
features of the present disclosure.
[0014] The present disclosure relates to methods and systems for
analysis and design considerations in High-Pressure and
High-Temperature (HPHT) subterranean oil and gas well systems. In
particular, the present disclosure relates to analyses and designs
corresponding to dual tubing systems. Specifically, annular fluid
expansion within sealed annuli can cause annular pressure buildup
within a wellbore. HPHT wellbores can be particularly susceptible
to rupture, therefore determining the expected pressure buildup
within the annular regions is essential for safe wellbore
design.
[0015] In order to increase the production of hydrocarbons from a
single wellbore, a dual tubing string can be used. Dual tubing
string arrangements can allow a single wellbore having tubulars
disposed therein to produce from two segregated zones. In at least
one instance, dual tubing operations can allow for simultaneous
production from more than one producing zone. In the alternative, a
dual tubing operation can be used to inject a material into one
zone of a wellbore while producing from a second zone of the
wellbore, which can assist in preventing backflow from one zone to
another. However, the dual tubing configurations can cause trapped
annulus fluid expansion (AFE) and trapped annulus pressure buildup
(APB) within the enclosed space of the tubing annulus. For example,
the systems and methods described herein can be used to determine
whether an internal region or an external region for a pair of
casing string annuli are open or closed and calculate the APB for
the trapped region. Such calculations are required where the
temperature of a fluid trapped within an enclosed container, such
as the annular space within a well system, changes. As the
temperature changes, the pressure within the container can also
change due to the expansion or shrinkage of the fluid. The methods
and systems described herein can be used to calculate the AFE/APB
values caused by temperature change from various operations during
a well lifecycle in a dual tubing well system. The calculations
made using the methods and systems herein can be applied to well
system design and analysis.
[0016] FIG. 1 illustrates an exemplary operation well system 100
that can employ the systems and methods disclosed herein. As shown,
the operational well system 100 can include a rig 102 located on an
earth formation 104. The rig 102 may include a drilling platform
106 and a derrick 108 located on the platform. The derrick 108 may
support or otherwise manipulate the position of a first tubing 110
and a second tubing 112 configured to be extended into a wellbore
114 drilled into the earth formation 104. In at least some
examples, the wellbore 114 can be a directional well, including one
or more bends. While FIG. 1 generally illustrates wellbore 114 as
having a single bend, it should be understood that in other
applications portions or substantially all of the wellbore 114 may
be vertical, deviated, horizontal, and/or curved. Additionally, the
wellbore 114 can include a casing 116 which can extend partially or
fully to the end of the first tubing 110 and the second tubing 112
of the wellbore 114. In some instances, the systems and methods
described herein can be used to design a well system prior to
drilling. In the alternative, the systems and methods described
herein can be used to analyze well systems 100 which are already
disposed within a subterranean formation. Such design and/or
analysis can be performed using a computing device 118 located in a
control or processing facility 120, as described in greater detail
below.
[0017] Modifications, additions, or omissions may be made to FIG. 1
without departing from the spirit and scope of the present
disclosure. For example, FIG. 1 depicts components of the
operational well system 100 in a particular configuration. However,
any suitable configuration of components may be used. Furthermore,
fewer components or additional components beyond those illustrated
may be included in the operational well system 100 without
departing from the spirit and scope of the present disclosure. It
should also be noted that while FIG. 1 generally depicts a
land-based operation, those skilled in the art would readily
recognize that the principles described herein are equally
applicable to operations that employ floating or sea-based
platforms and rigs, without departing from the scope of the
disclosure.
[0018] FIG. 2 illustrates a detailed view of a subsurface well 200
having two tubing stings and multiple casings disposed therein,
analysis of which is compatible with the methods and systems
described herein. As illustrated in FIG. 2, deep wells of the
instant type can include multiple concentric spaced apart casings
210. The space between consecutive casing pipes creates a plurality
of annuli 240. As depicted in FIG. 2, four concentric casings 210
with three annuli 240 therebetween, indicated using
single-direction cross-hatching, are disposed within the well 200.
In the present example, each annuli 240 is substantially closed at
a lower end with cement 250 and sealed off at an upper end to
assure that the well fluids contained therein do not escape into
the surrounding environment. As such, each of the annuli 240 in the
well 200 constitutes an "enclosed annulus" that has been filled
with a well fluid, referred to as "trapped annulus fluid."
Arrangements, such as the one illustrated in FIG. 2, typically
occur during the completion operations of the well system.
[0019] The innermost casing 212 of the well 200 constitutes a
production casing, within which the production tubing string(s) are
located. As illustrated in FIG. 2, two production tubing strings
having different lengths and are disposed within the well 200 and
are open at the distal end to different zones, or regions, of the
well 200. Tubing structures similar to those depicted in FIG. 2 are
referred to as "dual tubing." In the present example, the longer
tubing string 290 is open at a lower region 278, while the shorter
tubing string 292 is open at a higher region 280.
[0020] Modifications, additions, or omissions may be made to FIG. 2
without departing from the spirit and scope of the present
disclosure. It should also be noted that while FIG. 2 generally
depicts a vertical well section, those skilled in the art would
readily recognize that the principles described herein are equally
applicable to operations in inclined well sections, direction well
sections, horizontal well sections, and the like without departing
from the scope of the present disclosure.
[0021] As described above, well fluid that is trapped in the
annulus of a well system is considered "trapped annulus fluid."
Trapped annulus fluid expansion and annular pressure buildup
(AFE/APB) occur when the temperature of the fluid trapped within an
enclosed annulus changes. Unexpected pressure changes due to
expansion or shrinkage of a fluid in an enclosed container, such as
the trapped annular spaces in a well system, can have catastrophic
effects on the well including, but not limited to, well burst or
collapse. As such, determining the AFE and APB corresponding to
these trapped annular regions is critical to ensuring well
integrity during operations conducted throughout a well lifecycle.
However, due to the large number of trapped annular regions within
a dual-tubing system as shown above, such calculations are
exceedingly difficult. The present systems and methods address
issues relating to the calculations of trapped AFE and trapped APB
in such multi-tubing configurations. Specifically, the systems and
methods are designed to calculate the APB of a well system at each
of the various trapped annulus regions throughout the length of the
well.
[0022] In at least one instance, the present method can be used to
model different operating conditions having known characteristics
of the well analyzed to assure the well's integrity under that
operational condition. Such analysis can be performed during the
design phase of a new well or can be applied to an existing well to
determine its operational integrity. For instance, where a
production scenario is analyzed, such as that illustrated in FIG.
2, in which each of the dual tubing strings is used to produce
hydrocarbon from deep within the formation (such as regions 278 and
280 as shown in FIG. 2) the present methods can be used to
determine whether the well system will be prone to burst or
collapse.
[0023] An exemplary analysis is provided in FIGS. 3A-3B, including
iterative calculations to determine the AFE/APB throughout each
trapped region within the well system using a computing system
described in greater detail below. The analysis includes two
iterative loops. In the inner iteration loop, the AFE/APB is
calculated for each trapped region throughout the wellbore until
the change of storage volume of each region equals the volume
change of the fluid by expansion/shrinkage for that region. The
outer iteration loop calculates the global AFE/APB for the well
system as whole until all trapped regions of the well system
reaches a balanced pressure status. In these regards, the pressure
changes take into account the following aspects. The change in the
volume of a particular region (the trapped/enclosed space volume)
due to the change in pressure and temperature compared to the
initial conditions. This is due to the effect of Hooke's Law
(compressed string steel from increased pressure), the thermal
expansion/shrinkage of the steel, and also the ballooning effect.
Such AFE/APB calculations can be performed using two well system
states referred to herein as initial and final conditions. In at
least one instance, the initial and final conditions can correspond
to an original and an ending state of an operation.
[0024] Specifically, FIGS. 3A and 3B illustrate an exemplary method
300 for calculating pressures in a well system having one or more
trapped annulus regions. The method 300 can begin at block 302, as
shown in FIG. 3A, where the initial temperature(s) and pressure(s)
and the final temperature(s) for each enclosed annulus throughout
the wellbore is determined or assumed. In at least one instance,
"initial" temperature and pressure can refer to the undisturbed
subterranean condition (such as an undisturbed geothermal
temperature and static pressure) or drilling operation temperature
or pressure, or a production operation temperature and/or pressure.
In at least one instance, "final" temperature and pressure can
refer to a wellbore condition during a drilling, production, or
other wellbore operation.
[0025] In at least one instance, the initial temperature(s) and
pressure(s) can be measured using one or more sensors. In the
alternative, the initial temperature(s) and pressure(s) can be
assumed as approximately equal to the temperature and pressure of
the earth formation in which the well is located. Additionally at
block 302 the final temperature(s) is determined. For example,
temperatures within wellbores can change in a gradient. For
instance, the formation can get warmer as the wellbore descends. As
such, the temperatures throughout the wellbore can be "known,"
based on the expected temperature gradient throughout the length of
the wellbore. In addition, the fluid type, pressure, and density
corresponding to the initial temperature within the enclosed
annulus can also be determined or assumed. The method 300 can be
used to evaluate the integrity of a dual tubing system such as that
illustrated with respect to FIG. 2. In at least one instance, the
dual tubing system can be used to produce from two locations within
a wellbore. In such instance, a changed temperature gradient can be
applied to the well as the fluid moves up within the tubing to
estimate the initial and final temperatures. In other instances,
the analytical method 300 can be utilized in more complicated
scenarios. Such as a stimulation in which hot steam is injected
down through a first tubing (such as tubing 290 of FIG. 2) and into
the formation to "stimulate" hydrocarbon production up through a
second tubing (such as tubing 292 of FIG. 2). In this case, the
calculation of the vertical temperature gradient is significantly
more complicated, but nonetheless calculable using known methods to
arrive at the necessary initial and final temperatures, pressures,
and densities.
[0026] At block 304, the final pressure(s) are estimated as well as
the fluid type and density for each annulus.
[0027] While the initial and final temperatures and pressures are
defined as specific well conditions above, it should be understood
that both the initial and final condition can be any state of the
well life cycle.
[0028] The tubing strings and casings used in the well system must
be strong enough to prevent burst or collapse when the well system
is operating. As described above, a trapped annular region occurs
where a well fluid is enclosed within an annulus between two
casings. To assure a sufficiently robust well design, the effects
of pressure buildup in each of the trapped annular regions of the
enclosed annuli throughout the length of the wellbore must be
computed under the conditions identified in steps 302 and 304. In
order for the method 300 to balance the well system as a whole, at
block 306, each of the trapped annular regions within the system
are identified. Referring back to FIG. 2, such regions can include
trapped annular regions filled with well fluid and closed off with
packers. Because the temperature gradient and density of the
trapped fluid within the enclosed annulus is known (as determined
above), the expanded volume and pressure of the trapped annular
region and trapped annulus fluid can be calculated. At block 308, a
single trapped annular region is selected for analysis.
[0029] Since the size and spacing of the casings are known, the
interior volume of the "enclosure" can easily be calculated. For
example, the length of each casing and location of cement, packer,
or other sealing device are considered known as a user performing
the simulation can provide such variables to the program.
Additionally, the elasticity of the enclosure must be considered as
well as any relevant exterior forces acting thereupon. At block
310, the method 300 determines whether the type of trapped region,
or enclosure, being analyzed. Specifically, if the trapped annulus
is a casing annulus, where the material on either side of the
enclosure is a casing, the method 300 can proceed to block 312
where the volume change of the casing annulus is determined based
on the original volume of the trapped space. In the alternative, if
the trapped space is a tubing annulus, where the annulus is
disposed between two tubing strings or between a tubing string and
a casing, the method 300 can proceed to block 314 where the volume
change must be determined for both the tubing and the surrounding
casings. It should be appreciated that it is not only "burst"
strength of the enclosure that is relevant, but collapse of the
trapped space can also occur and therefore must be taken into
account. For example, in analyzing a trapped region such as an
enclosed annulus about the production strings, such as that
illustrated as region 270 in FIG. 2, the pressure can "press" into
the tubing volume, effectively increasing the volume of the trapped
space, and as a result, buffer the pressure buildup.
[0030] The change in volume of the enclosed space for either block
312 or block 324 can be represented by the following function based
on temperature and pressure:
dV.sub.s=f(P,T,dP,dT, . . . )
It should be understood that the calculations of volume change in
both block 312 and block 314 are determined without reference to
the fluid enclosed therein.
[0031] The method 300 can then proceed to block 316, where the
annular fluid expansion (AFE) due to temperature change is
determined for the fluid enclosed within the trapped region
selected for analysis. Specifically, using the known values for
temperature and pressure, as well as the density/compressibility of
the entrapped well fluid, the expansion or shrinkage of the fluid
in response to temperature changes can be determined. For example,
the change in the volume of the entrapped fluid caused by the
temperature change can be expressed by the following function:
dV.sub.f=f(dT,V, . . . )
[0032] Once the change in volume of the entrapped fluid is
determined, the method 300 can proceed to block 318, as illustrated
in FIG. 3B, where the pressure change within the trapped region can
be calculated. Specifically, at block 318, the annular pressure
change (or APB), which is typically an increase, within the
enclosure is calculated. In addition, the capability of the
enclosure to satisfactorily contain the pressure can be determined.
For example, the APB for a balanced enclosure is determined, where
dV.sub.s=dV.sub.f as explained in detail below.
[0033] The conditions that determine the APB, or pressure increase,
are those in existence when the volume change of the enclosure
equals the volume change of the entrapped fluid
(expansion/shrinkage), as calculated in steps 312-316 above. This
can be expressed by the following function:
APB=dP=f(dV.sub.fdV.sub.s,dT, . . . )
[0034] For example, when the temperature increases, the trapped
fluid expands. If the enclosed volume did not change, then fluid
volume (AFE) will not be changed, and the pressure will be
increased in order to compress the "expanded" fluid volume to
return to the original fluid volume. In such case, since the
pressure is increased, the enclosed space volume is be enlarged.
The changes need to be balanced so that the changed enclosed space
volume is equal to the change of the fluid volume from the
temperature. For example, the volume of the enclosure dV.sub.s is
compared to the calculated volume of the entrapped fluid dV.sub.f.
If dV.sub.s=dV.sub.f, the trapped region is balanced. However, if
dV.sub.s*dV.sub.f, the pressure must be changed in order to achieve
a balanced trapped region. Specifically, if the enclosure of the
trapped area does not have an enclosure volume change (dV.sub.s=0),
this indicates that the enclosure is rigid. However, the fluid
trapped within the enclosure can be subject to expansion and
shrinkage as a result of temperature change (dV.sub.f.noteq.0). In
order for the fluid to remain within the enclosure, a pressure is
applied to compress the fluid into the available enclosure volume.
The pressure that is applied to the fluid is the APB. However,
where the enclosure volume can change due to deformation of the
tubing string or casing (i.e., in response to the pressure applied
to the tubing string or casing and the ballooning/anti-ballooning
effect) and APB work against one another. When the APB is too low,
the enclosure volume change can be too small to contain the
expanded fluid. As such, increasing the pressure within the
enclosure can reduce the fluid expansion volume so that the
enclosure is balanced. Once the trapped region is balanced, the
method 300 can proceed to block 320.
[0035] At block 320, the method 300 determines whether there are
additional trapped regions within the well system For example, if
there are additional trapped regions the volume change of the
enclosure, AFE, and APB must be calculated for each. In such case,
the method 300 returns to block 308 where a next trapped region is
selected and the process is repeated. The calculation is reiterated
until a volume change, AFE, and APB has been calculated for each
trapped region existing within the well system, completing the
inner loop of the method 300. Once the calculations are complete,
the method 300 can proceed to block 322, where the calculations are
updated and recorded for each region.
[0036] At block 324, the method 300 can then determine whether the
well system is balanced for all of the trapped annular regions. It
should be appreciated that adjacent enclosed annuli can affect one
another; such affects are taken into account in this outer loop of
the present method. Specifically, the pressure buildup in each of
the annular regions throughout the well bore must be balanced to
prevent well rupture. For example, the inner annulus and outer
annulus of a casing can both be subject to pressure changes, the
ballooning effect of one annulus will affect the APB for both sides
of the casing. The balancing step is necessary to ensure the
ballooning effect is applied to both sides of the casing globally.
For example, when the APB for a first region is calculated as
described above, it is assumed that the pressure applied on the
other side of the surrounding string is constant. However, when
taking each of the trapped annular regions into account the effect
of a first trapped annular region on a second trapped annular
region that shares a casing or tubing string wall must be taken
into account. Due to the shared wall, an enclosure volume change in
the first region has a clear effect on the enclosure volume of the
second region, which can result in one or both regions becoming
unbalanced. Therefore, the AFE and APB calculations must be
iterated taking the adjacent trapped annular regions into
account.
[0037] Referring to the example illustrated in FIG. 2, trapped
annular regions exist. The calculation of volume change, AFE, and
APB for the annulus about the dual tubing strings (illustrated as
region 270) can be complicated due to the presence of multiple
tubing strings as well as several additional trapped annular
regions (illustrated as regions 272, 274, 276) enclosed by packers.
Each entrapped annular region can have a substantial impact on the
overall well design or integrity analysis of an existing well. If
the well system is not balanced throughout each of the trapped
regions, the method 300 returns to block 308, and the calculations
are repeated until a balance is achieved.
[0038] Once the well system is balanced, the method 300 can proceed
to block 326, where the data obtained from the above calculations
is output for each of the trapped annular regions. An exemplary
output showing typical results is provided as Table 1, below.
TABLE-US-00001 TABLE 1 Pressure Volume Differential Differential
Region Due to AFE Due to AFE String Annulus Top (ft) Base (ft)
(psi)* (bbl)** 20'' Surface Casing Region 1 40.0 450.0 2346.00 1.2
16'' Intermediate Casing Region 1 40.0 6000.0 4365.00 15.4 133/8''
Protective Casing Region 1 40.0 9200.0 5198.00 9.7 103/4''
Production Tieback Region 1 40.0 14000.0 6324.00 6.5 41/2''
Production Tubing Region 1 40.0 12000.0 9369.00 15.4 31/2''
Production Tubing *Pressure change caused solely by the Annular
Fluid Expansion (AFE) phenomenon **Volume change caused solely by
the Annular Fluid Expansion (AFE) effect
[0039] As indicated in Table 1, the pressure change due to annular
fluid expansion within an entrapped region can be extremely high,
such as on the order of thousands of pounds per square inch (psi).
As described above, such pressure changes can have a dramatic
impact on the safety of the resulting well system. Calculation of
the AFE/APB effect is therefore crucial during well system design
and analysis in order to produce a well system that is safe
throughout the well lifecycle and operations including, but not
limited to, circulation, injection, and production. In at least one
example, the method 300 can be implement using advanced tubular
design software for design and analysis of tubular wellbores. In
addition to well system design, the present methods can be
implemented on an existing well to determine the integrity of the
well system and ability of the well to perform one or more
operations.
[0040] In at least one instance, the data generated above can be
used to produce a graphical representation of the bounds of a safe
wellbore. Specifically, the information can be applied to the
design of a well system, such as those described above including
multiple tubing strings, using the worst-case scenario design
principle. Accompanying FIG. 4 provides a graphical representation
of the corresponding design limit. For example, the graph depicts
an envelop encompassing the bounds of a safe well system design for
the well depicted in FIG. 2. Specifically, the simulation
illustrated in FIG. 4 provides design limits for a 103/4 inch
production tieback having an outer diameter of 10.750 inches. The
graph illustrates the well wherein a steam injection operation is
performed using the longer tubing 290 and a production operation is
performed using the shorter tubing 292.
[0041] In the graph, the initial conditions are represented using a
solid line having circular data points. Using worst-case design
principles, the effect of APB is demonstrated on the graph. It has
been shown that once the APB is applied to a simulation, the
initial safe design can become unsafe as indicated by the load
points outside the safety design limit envelop 400. When this
occurs, the string must be redesigned in order to assure safe well
integrity. In FIG. 4, the "Max Collapse," illustrated by a dashed
line and square data points, indicates where the APB pressure is
applied to the external pressure of the string; "Max Burst,"
indicated with a dash-dot line and diamond data points, indicates
where the APB pressure is applied to the internal pressure of the
string; and "AFE," illustrated by a dashed line and triangular data
points, indicates where both internal and external pressures are
applied in the establishment of APB. Specifically, in the present
graphical representation, the items 400, 410, 420, 430 are safety
design limit envelops based on various criteria, a safe design is
located in the overlap of each of these envelops. For example, 400
represents API collapse limit, 410 represents the von Mises
envelope, 420 represents API burst limit, 430 represents tension
limit, and 440 represents the load condition of the string in the
envelop. A well system design is safe and functional for the
temperatures and pressures within the envelop. However, the design
will fail if the well system experiences temperature and pressure
changes which results in a load condition of the string outside the
envelop. As such, the method 300 described above can generate a
graphical representation of the temperatures and pressure a well
system can experience without failure. Such graphs can be used to
confirm the safety of a design or to encourage adjustments to the
design (including, but not limited to, material selection;
wellbore, tubing, and casing reselection; packer placement; annular
fluid selection; and any other design change that can have an
impact on enclosure volume, fluid expansion, and pressure, and the
strength of the strings.). In order to ensure the design is safe
for the lifecycle of the well system, several pair of initial
conditions and final conditions which can be encountered during the
well system lifecycle can be applied to calculate the APB/AFE to
ensure the design is safe.
[0042] In the alternative, if the method 300 is used to evaluate
the integrity of a pre-existing well system, the graphical
representation produced can be used to determine safe operating
conditions. In addition, the graphical representation can provide
an indication of which operating conditions will cause the well
system to fail.
[0043] Simulations as described above can be completed on a
computing device using an advanced tubular design software suite
for well system design and analysis. Typical well design software
only provides a stress analysis for a single tubing string well
system, but cannot provide the detailed analysis of a multi-string
well system as described above. In at least one instance, the
advanced software can be integrated into current software, such as
WELLCAT, DWP, or other related software programs to enhance the
program's capacity for design and analysis. Simulations, such as
those described above, can be performed using a computing device
118 such as that described with respect to FIG. 1. Exemplary
computing devices capable of performing the methods described
herein are described in detail below.
[0044] Processing facility 120 and computing device 118 may include
any suitable computer, controller, or data processing apparatus
capable of being programmed to carry out the method, system, and
apparatus as further described herein. FIGS. 5A and 5B illustrate
exemplary processing facility 120 and computing device 118 that can
be employed to practice the concepts, methods, and techniques
disclosed herein. The more appropriate embodiment will be apparent
to those of ordinary skill in the art when practicing the present
technology. Persons of ordinary skill in the art will also readily
appreciate that other system embodiments are possible.
[0045] FIG. 5A illustrates a conventional system bus computing
system architecture 500 wherein the components of the system are in
electrical communication with each other using a bus 505. System
500 can include a processing unit (CPU or processor) 510 and a
system bus 505 that couples various system components including the
system memory 515, such as read only memory (ROM) 520 and random
access memory (RAM) 535, to the processor 510. The system 500 can
include a cache of high-speed memory connected directly with, in
close proximity to, or integrated as part of the processor 510. The
system 500 can copy data from the memory 515 and/or the storage
device 530 to the cache 512 for quick access by the processor 510.
In this way, the cache 512 can provide a performance boost that
avoids processor 510 delays while waiting for data. These and other
modules can control or be configured to control the processor 510
to perform various actions. Other system memory 515 may be
available for use as well. The memory 515 can include multiple
different types of memory with different performance
characteristics. In at least one instance, the memory 515 can
include a well design system, such as WELLCAT, as well as a APB
simulation module to assist in the analysis described herein. It
can be appreciated that the disclosure may operate on a computing
device 500 with more than one processor 510 or on a group or
cluster of computing devices networked together to provide greater
processing capability. The processor 510 can include any general
purpose processor and a hardware module or software module, such as
first module 532, second module 534, and third module 536 stored in
storage device 530, configured to control the processor 510 as well
as a special-purpose processor where software instructions are
incorporated into the actual processor design. The processor 510
may essentially be a completely self-contained computing system,
containing multiple cores or processors, a bus, memory controller,
cache, etc. A multi-core processor may be symmetric or
asymmetric.
[0046] The system bus 505 may be any of several types of bus
structures including a memory bus or a memory controller, a
peripheral bus, and a local bus using any of a variety of bus
architectures. A basic input/output (BIOS) stored in ROM 520 or the
like, may provide the basic routine that helps to transfer
information between elements within the computing device 500, such
as during start-up. The computing device 500 further includes
storage devices 530 or computer-readable storage media such as a
hard disk drive, a magnetic disk drive, an optical disk drive, tape
drive, solid-state drive, RAM drive, removable storage devices, a
redundant array of inexpensive disks (RAID), hybrid storage device,
or the like. The storage device 530 can include software modules
532, 534, 536 for controlling the processor 510. The system 500 can
include other hardware or software modules. The storage device 530
is connected to the system bus 505 by a drive interface. The drives
and the associated computer-readable storage devices provide
non-volatile storage of computer-readable instructions, data
structures, program modules and other data for the computing device
500. In one aspect, a hardware module that performs a particular
function includes the software components shorted in a tangible
computer-readable storage device in connection with the necessary
hardware components, such as the processor 510, bus 505, and so
forth, to carry out a particular function. In the alternative, the
system can use a processor and computer-readable storage device to
store instructions which, when executed by the processor, cause the
processor to perform operations, a method or other specific
actions. The basic components and appropriate variations can be
modified depending on the type of device, such as whether the
device 500 is a small, handheld computing device, a desktop
computer, or a computer server. When the processor 510 executes
instructions to perform "operations," the processor 510 can perform
the operations directly and/or facilitate, direct, or cooperate
with another device or component to perform the operations.
[0047] To enable user interaction with the computing device 500, an
input device 545 can represent any number of input mechanisms, such
as a microphone for speech, a touch-sensitive screen for gesture or
graphical input, keyboard, mouse, motion input, speech and so
forth. An output device 542 can also be one or more of a number of
output mechanisms known to those of skill in the art. In some
instances, multimodal systems can enable a user to provide multiple
types of input to communicate with the computing device 500. The
communications interface 540 can generally govern and manage the
user input and system output. There is no restriction on operating
on any particular hardware arrangement and therefore the basic
features here may easily be substituted for improved hardware or
firmware arrangements as they are developed.
[0048] Storage device 530 is a non-volatile memory and can be a
hard disk or other types of computer readable media which can store
data that are accessible by a computer, such as magnetic cassettes,
flash memory cards, solid state memory devices, digital versatile
disks (DVDs), cartridges, RAMs 525, ROM 520, a cable containing a
bit stream, and hybrids thereof.
[0049] The logical operations for carrying out the disclosure
herein may include: (1) a sequence of computer implemented steps,
operations, or procedures running on a programmable circuit with a
general use computer, (2) a sequence of computer implemented steps,
operations, or procedures running on a specific-use programmable
circuit; and/or (3) interconnected machine modules or program
engines within the programmable circuits. The system 500 shown in
FIG. 5A can practice all or part of the recited methods, can be a
part of the recited systems, and/or can operate according to
instructions in the recited tangible computer-readable storage
devices.
[0050] One or more parts of the example computing device 500, up to
and including the entire computing device 500, can be virtualized.
For example, a virtual processor can be a software object that
executes according to a particular instruction set, even when a
physical processor of the same type as the virtual processor is
unavailable. A virtualization layer or a virtual "host" can enable
virtualized components of one or more different computing devices
or device types by translating virtualized operations to actual
operations. Ultimately however, virtualized hardware of every type
is implemented or executed by some underlying physical hardware.
Thus, a virtualization compute layer can operate on top of a
physical compute layer. The virtualization compute layer can
include one or more of a virtual machine, an overlay network, a
hypervisor, virtual switching, and any other virtualization
application.
[0051] The processor 510 can include all types of processors
disclosed herein, including a virtual processor. However, when
referring to a virtual processor, the processor 510 includes the
software components associated with executing the virtual processor
in a virtualization layer and underlying hardware necessary to
execute the virtualization layer. The system 500 can include a
physical or virtual processor 510 that receives instructions stored
in a computer-readable storage device, which causes the processor
510 to perform certain operations. When referring to a virtual
processor 510, the system also includes the underlying physical
hardware executing the virtual processor 510.
[0052] FIG. 5B illustrates an example computer system 550 having a
chipset architecture that can be used in executing the described
method and generating and displaying a graphical user interface
(GUI). Computer system 550 can be computer hardware, software, and
firmware that can be used to implement the disclosed technology.
System 550 can include a processor 555, representative of any
number of physically and/or logically distinct resources capable of
executing software, firmware, and hardware configured to perform
identified computations. Processor 555 can communicate with a
chipset 560 that can control input to and output from processor
555. Chipset 560 can output information to output device 565, such
as a display, and can read and write information to storage device
570, which can include magnetic media, and solid state media.
Chipset 560 can also read data from and write data to RAM 575. A
bridge 580 for interfacing with a variety of user interface
components 585 can include a keyboard, a microphone, touch
detection and processing circuitry, a pointing device, such as a
mouse, and so on. In general, inputs to system 550 can come from
any of a variety of sources, machine generated and/or human
generated.
[0053] Chipset 560 can also interface with one or more
communication interfaces 590 that can have different physical
interfaces. Such communication interfaces can include interfaces
for wired and wireless local area networks, for broadband wireless
networks, as well as personal area networks. Some applications of
the methods for generating, displaying, and using the GUI disclosed
herein can include receiving ordered datasets over the physical
interface or be generated by the machine itself by processor 555
analyzing data stored in storage 570 or RAM 575. Further, the
machine can receive inputs from a user via user interface
components 585 and execute appropriate functions, such as browsing
functions by interpreting these inputs using processor 555.
[0054] It can be appreciated that systems 500 and 550 can have more
than one processor 510, 555 or be part of a group or cluster of
computing devices networked together to provide processing
capability. For example, the processor 510, 555 can include
multiple processors, such as a system having multiple, physically
separate processors in different sockets, or a system having
multiple processor cores on a single physical chip. Similarly, the
processor 510 can include multiple distributed processors located
in multiple separate computing devices, but working together such
as via a communications network. Multiple processors or processor
cores can share resources such as memory 515 or the cache 512, or
can operate using independent resources. The processor 510 can
include one or more of a state machine, an application specific
integrated circuit (ASIC), or a programmable gate array (PGA)
including a field PGA.
[0055] Methods according to the aforementioned description can be
implemented using computer-executable instructions that are stored
or otherwise available from computer readable media. Such
instructions can comprise instructions and data which cause or
otherwise configured a general purpose computer, special purpose
computer, or special purpose processing device to perform a certain
function or group of functions. Portions of computer resources used
can be accessible over a network. The computer executable
instructions may be binaries, intermediate format instructions such
as assembly language, firmware, or source code. Computer-readable
media that may be used to store instructions, information used,
and/or information created during methods according to the
aforementioned description include magnetic or optical disks, flash
memory, USB devices provided with non-volatile memory, networked
storage devices, and so on.
[0056] For clarity of explanation, in some instances the present
technology may be presented as including individual functional
blocks including functional blocks comprising devices, device
components, steps or routines in a method embodied in software, or
combinations of hardware and software. The functions these blocks
represent may be provided through the use of either shared or
dedicated hardware, including, but not limited to, hardware capable
of executing software and hardware, such as a processor 510, that
is purpose-built to operate as an equivalent to software executing
on a general purpose processor. For example, the functions of one
or more processors represented in FIG. 5A may be provided by a
single shared processor or multiple processors (use of the term
"processor" should not be construed to refer exclusively to
hardware capable of executing software). Illustrative embodiments
may include microprocessor and/or digital signal processor (DSP)
hardware, ROM 520 for storing software performing the operations
described below, and RAM 535 for storing results. Very large scale
integration (VLSI) hardware embodiments, as well as custom VLSI
circuitry in combination with a general-purpose DSP circuit, may
also be provided.
[0057] The computer-readable storage devices, mediums, and memories
can include a cable or wireless signal containing a bit stream and
the like. However, when mentioned, non-transitory computer-readable
storage media expressly exclude media such as energy, carrier
signals, electromagnetic waves, and signals per se.
[0058] Devices implementing methods according to these disclosures
can comprise hardware, firmware and/or software, and can take any
of a variety of form factors. Such form factors can include
laptops, smart phones, small form factor personal computers,
personal digital assistants, rackmount devices, standalone devices,
and so on. Functionality described herein also can be embodied in
peripherals or add-in cards. Such functionality can also be
implemented on a circuit board among different chips or different
processes executing in a single device.
[0059] The instructions, media for conveying such instructions,
computing resources for executing them, and other structures for
supporting such computing resources are means for providing the
functions described in the present disclosure. In at least one
instance, the computing system for implementing the present
disclosure can include a memory as described above, one or more
programs including an APB simulation program and a well design
program, and an interface (including, but not limited to an output
device or GUI as described above). In at least one instance, the
APB simulation module can include a plurality of sub-modules which
are capable of evaluating various aspects of the well system which
can be effected by APB. For example, the plurality of sub-modules
can include, but are not limited to, a drilling prediction module,
a production prediction module, a casing stress module, a tubing
stress module, and a multi-string module. The memory can store the
application programs, which may also be described as program
modules containing computer-executable instructions, executed by
the computing device for implementing the present disclosure.
[0060] Specifically, a user can input starting parameters
including, but not limited to, initial temperatures and pressures
corresponding to the well system to be simulated. The computing
device can use the well design system to create a diagrammatic
representation of the desired well system and the APB simulation
module to simulate the pressure changes the well system will
experience. The computing device can then proceed with the method
300 as described above to determine a balanced system using the
initial well system inputs provided by the user. In at least one
instance, the computing device as described above can provide a
graphical representation of the simulation, as illustrated in FIGS.
6A-6C. Specifically, FIG. 6A illustrates a graphical representation
of the section reference plan through the wellhead origin on
azimuth 0.0. The computing display can also provide a diagrammatic
representation of a horizontal well system. FIG. 6B illustrates a
dual-tubing completion operation. As indicated, the well system
being simulated in the present example is a two-string system
having packers disposed within the annuli. FIG. 6C illustrates a
graphical representation of axial load effect of the tubing strings
of FIG. 6B. The simulation provides information corresponding to
the annulus fluid expansion. In at least one example, additional
information can be displayed to a user regarding the fluid
expansion as well as pressure buildup in various trapped regions
throughout the length of the wellbore.
[0061] Numerous examples are provided herein to enhance
understanding of the present disclosure. A specific set of
statements are provided as follows.
[0062] Statement 1: A method for designing a well system envelop,
the method comprising creating an initial design for a well system
including two or more tubing strings disposed within a well, the
well system including one or more trapped annular regions therein,
each of the one or more trapped annular regions including an
enclosure; determining a plurality of initial temperatures, a
plurality of final temperatures, and an initial pressure for each
of the one or more trapped annular regions; estimating a final
pressure for each of the one or more trapped annular regions;
analyzing each of the one or more trapped annular regions; and
generating a wellbore system envelop based at least in part on the
analysis of each of the one or more trapped annular regions.
[0063] Statement 2: A method in accordance with Statement 1,
wherein analyzing the one or more trapped annular regions further
comprises selecting a first trapped region from the one or more
trapped annular regions; calculating an enclosure volume change for
the first trapped region; and calculating an annular fluid
expansion (AFE) of a well fluid contained within the enclosure of
the first trapped region, the AFE corresponding to a fluid volume
change caused by a temperature change.
[0064] Statement 3: A method in accordance with Statement 1 or
Statement 2, wherein analyzing the one or more trapped annular
regions further comprises determining an annular pressure buildup
(APB) corresponding to the first trapped region, wherein when the
enclosure volume change for the first trapped region is balanced
with the AFE for the first trapped region.
[0065] Statement 4: A method in accordance with Statements 1-3,
further comprising calculating a plurality of APBs corresponding to
each of the plurality of initial temperatures and the plurality of
final temperatures.
[0066] Statement 5: A method in accordance with Statements 1-4,
wherein when the well system further includes at least two casings
the enclosure of the one or more trapped annular regions includes
one or more casing enclosures between two casings, one or more
casing and tubing enclosures between a casing and a tubing string,
and one or more tubing enclosures between two tubing strings.
[0067] Statement 6: A method in accordance with Statements 1-5,
further comprising calculating a respective enclosure volume
change, a plurality of respective AFEs, and a plurality of
respective APBs for each of the remaining one or more trapped
annular regions.
[0068] Statement 7: A method in accordance with Statements 1-6,
further comprising iterating the calculations of the plurality of
respective APBs for each of the one or more trapped annular regions
assuming a non-rigid enclosure.
[0069] Statement 8: A method in accordance with Statements 1-7,
further comprising determining whether a global pressure of the
well system is balanced for each of the one or more trapped annular
regions within the well system based on the non-rigid
enclosures.
[0070] Statement 9: A method in accordance with Statements 1-8,
further comprising generating a graphical representation of the of
the wellbore system envelop showing a safe design limit, and
transmitting the graphical representation to an output device.
[0071] Statement 10: A method in accordance with Statements 1-9,
wherein the plurality of initial temperatures, the initial
pressure, and the plurality of final temperatures for each of the
one or more trapped annular regions are determined using
calculations and/or simulation.
[0072] Statement 11: A non-transitory computer-readable storage
medium storing computer-executable instructions which, when
executed by one or more processors, cause the one or more
processors to create initial design for a well system including two
or more tubing strings disposed within a well, the well system
including one or more trapped annular regions therein, each of the
one or more trapped annular regions including an enclosure;
determine a plurality of initial temperatures, a plurality of final
temperatures, and an initial pressure for each of the one or more
trapped annular regions; estimate a final pressure for each of the
one or more trapped annular regions; analyze each of the one or
more trapped annular regions; and generate a wellbore system
envelop based at least in part on the analysis of each of the one
or more trapped annular regions.
[0073] Statement 12: A non-transitory computer-readable storage
medium in accordance with Statement 11, wherein the instructions
further cause the processor to select a first trapped region from
the one or more trapped annular regions; calculate an enclosure
volume change for the first trapped region; and calculate an
annular fluid expansion (AFE) of a well fluid contained within the
enclosure of the first trapped region, the AFE corresponding to a
fluid volume change caused by a temperature change.
[0074] Statement 13: A non-transitory computer-readable storage
medium in accordance with Statement 11 or Statement 12, wherein the
instructions further cause the processor to determine an annular
pressure buildup (APB) corresponding to the first trapped region,
wherein the enclosure volume change for the first trapped region is
balanced with the AFE for the first trapped region.
[0075] Statement 14: A non-transitory computer-readable storage
medium in accordance with Statements 11-13, wherein the
instructions further cause the processor to calculate a plurality
of APBs corresponding to each of the plurality of initial
temperatures and the plurality of final temperatures.
[0076] Statement 15: A non-transitory computer-readable storage
medium in accordance with Statements 11-14, wherein when the well
system further includes at least two casings the enclosure of the
one or more trapped annular regions includes one or more casing
enclosures between two casings, one or more casing and tubing
enclosures between a casing and a tubing string, and one or more
tubing enclosures between two tubing strings.
[0077] Statement 16: A non-transitory computer-readable storage
medium in accordance with Statements 11-15, wherein the
instructions further cause the processor to calculate a respective
enclosure volume change, a plurality of respective AFEs, and a
plurality of respective APBs for each of the remaining one or more
trapped annular regions.
[0078] Statement 17: A non-transitory computer-readable storage
medium in accordance with Statements 11-16, wherein the
instructions further cause the processor to iteratively calculate a
plurality of respective APBs for each of the one or more trapped
annular regions assuming a non-rigid enclosure.
[0079] Statement 18: A non-transitory computer-readable storage
medium in accordance with Statements 11-17, wherein the
instructions further cause the processor to determine whether a
global pressure of the well system is balanced for each of the one
or more trapped annular regions within the well system based on the
non-rigid enclosures.
[0080] Statement 19: A non-transitory computer-readable storage
medium in accordance with Statements 11-18, wherein when the well
system is balanced the instructions further cause the processor to
generate a graphical representation of the well system envelop
showing a safe design limit; and display the well system envelop
and the safe design limit on an output device communicatively
coupled with the one or more processors.
[0081] Statement 20: A non-transitory computer-readable storage
medium in accordance with Statements 11-19, wherein the plurality
of initial temperatures, the initial pressure, and the plurality of
final temperatures for each of the one or more trapped annular
regions are determined using calculations and/or simulation.
[0082] Statement 21: A system comprising a well system including a
wellbore having at least two tubing strings and at least one casing
disposed therein, the well system including a plurality of trapped
annular regions, each of the plurality of trapped annular regions
being a non-rigid enclosure; one or more processors coupled with an
input device; and at least one non-transitory computer-readable
storage medium storing instructions which, when executed by the one
or more processors, cause the one or more processors to receive a
plurality of initial temperatures, an initial pressure, and a
plurality of final temperatures corresponding to each of the
plurality of trapped annular regions from one or more sensors
located within the wellbore of the well system; estimate a final
pressure for each of the one or more trapped annular regions;
analyze each of the one or more trapped annular regions; and
generate an integrity report for the well system, wherein the
integrity report is based at least in part on the analysis of each
of the plurality of trapped annular regions.
[0083] Statement 22: A system in accordance with Statement 21,
wherein the integrity report includes a temperature range and a
pressure range at which the well system will fail.
[0084] Statement 23: A system in accordance with Statement 21 or
Statement 22, wherein the instructions further cause the processor
to select a first trapped region from the one or more trapped
annular regions; calculate an enclosure volume change for the first
trapped region; and calculate an annular fluid expansion (AFE) of a
well fluid contained within the enclosure of the first trapped
region, the AFE corresponding to a fluid volume change caused by a
temperature change.
[0085] Statement 24: A system in accordance with Statements 21-23,
wherein the instructions further cause the processor to determine
an annular pressure buildup (APB) corresponding to the first
trapped region, wherein the enclosure volume change for the first
trapped region is balanced with the AFE for the first trapped
region.
[0086] Statement 25: A system in accordance with Statements 21-24,
wherein the instructions further cause the processor to calculate a
plurality of APBs corresponding to each of the plurality of initial
temperatures and the plurality of final temperatures.
[0087] Statement 26: A system in accordance with Statements 21-25,
wherein the instructions further cause the processor to calculate a
respective enclosure volume change, a plurality of respective AFEs,
and a plurality of respective APBs for each of the remaining one or
more trapped annular regions.
[0088] Statement 27: A system in accordance with Statements 21-26,
wherein the instructions further cause the processor to iteratively
calculate a plurality of respective APBs for each of the one or
more trapped annular regions assuming a non-rigid enclosure.
[0089] The embodiments shown and described above are only examples.
Even though numerous characteristics and advantages of the present
technology have been set forth in the foregoing description,
together with details of the structure and function of the present
disclosure, the disclosure is illustrative only, and changes may be
made in the detail, especially in matters of shape, size and
arrangement of the parts within the principles of the present
disclosure to the full extent indicated by the broad general
meaning of the terms used in the attached claims. It will therefore
be appreciated that the embodiments described above may be modified
within the scope of the appended claims.
* * * * *