U.S. patent application number 15/562528 was filed with the patent office on 2018-04-05 for shale geomechanics for multi-stage hydraulic fracturing optimization in resource shale and tight plays.
The applicant listed for this patent is LANDMARK GRAPHICS CORPORATION. Invention is credited to Junghun LEEM, Juan J. REYNA.
Application Number | 20180094514 15/562528 |
Document ID | / |
Family ID | 57178600 |
Filed Date | 2018-04-05 |
United States Patent
Application |
20180094514 |
Kind Code |
A1 |
LEEM; Junghun ; et
al. |
April 5, 2018 |
SHALE GEOMECHANICS FOR MULTI-STAGE HYDRAULIC FRACTURING
OPTIMIZATION IN RESOURCE SHALE AND TIGHT PLAYS
Abstract
Systems and methods for improving production from wellbores
include providing optimal fracture design parameters based on
geomechanical analyses combined with geological, geophysical,
and/or petrophysical knowledge. In at least one embodiment, the
systems and methods include defining a well direction, defining a
fracture spacing, selecting a fracturing fluid system and
optimizing a fracture design, such as a complex multi-stage
hydraulic fracture design. Such systems and methods can help
minimize a learning curve associated with a wellbore or
subterranean formation and optimize the hydraulic fracturing
operation for a hydrocarbon reservoir.
Inventors: |
LEEM; Junghun; (Warsaw,
PL) ; REYNA; Juan J.; (The Woodlands, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
LANDMARK GRAPHICS CORPORATION |
Houston |
TX |
US |
|
|
Family ID: |
57178600 |
Appl. No.: |
15/562528 |
Filed: |
April 30, 2015 |
PCT Filed: |
April 30, 2015 |
PCT NO: |
PCT/US2015/028578 |
371 Date: |
September 28, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/26 20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A computer-implemented method of designing a hydraulic
fracturing operation for a hydrocarbon reservoir, comprising:
defining an anisotropy of a formation material in the reservoir;
defining a heterogeneity of a formation material in the reservoir;
creating, in computer readable storage, an electronically stored
geomechanical model of at least a portion of the reservoir based on
at least the anisotropy and the heterogeneity, wherein the
geomechanical model exhibits a prediction of at least one of pore
pressure and in-situ stresses within the portion of the reservoir;
defining a wellbore path in the geomechanical model through the
portion of the reservoir; identifying an estimated hydraulic
fracturing geometry of the portion of the reservoir at first and
second fracturing locations along the wellbore path, wherein the
estimated hydraulic fracturing geometry is based on at least one of
a geostress and a formation material mechanical property existing
at the first and second fracturing locations; creating, in computer
readable storage, an electronically stored fracturing geometry
model of the estimated hydraulic fracturing geometry at the first
and second fracturing locations; estimating a first stimulated
reservoir volume of the portion of the reservoir; adding to the
electronically stored fracturing geometry model an estimated
hydraulic fracturing geometry at a third fracturing location along
the wellbore path between the first and second fracturing
locations; calculating a manipulated stress anisotropy of the
portion of the reservoir based on the addition of the estimated
hydraulic fracturing geometry at the third fracturing location;
estimating a second stimulated reservoir volume of the portion of
the reservoir; and calculating a difference between the first
stimulated reservoir volume and the second stimulated reservoir
volume.
2. The method of claim 1, further comprising iteratively changing
at least one variable within the fracturing geometry model,
recalculating the manipulated stress anisotropy, and estimating a
third stimulated reservoir volume of the portion of the
reservoir.
3. The method of claim 2, wherein the at least one variable is
selected from the group consisting of well interval, perforation
interval, perforation order and a combination thereof.
4. The method of claim 1, further comprising performing a numerical
stress analysis of a reservoir interval between the first and
second fracturing locations.
5. The method of claim 1, wherein the third fracturing location is
disposed within a reservoir interval and located a first
perforation interval from the first fracturing location and a
second perforation interval from the second fracturing location,
and wherein the method further comprises determining a change in
stress in one or more directions within the reservoir interval.
6. The method of claim 5, further comprising determining a change
in treating pressure based on the change in stress.
7. The method of claim 5, further comprising determining a
likelihood that hydraulic fracturing at the third fracturing
location will cause fractures of increased complexity in the
reservoir interval between the first and second fracturing
locations.
8. The method of claim 5, further comprising determining a
manipulated horizontal stress anisotropy (HSAI*) of the reservoir
interval based on the first and second perforation intervals,
wherein HSAI* is determined according to the equation: HSAI * = SH
- Sh * Sh * . ##EQU00005##
9. The method of claim 8, further comprising determining a
plurality of HSAI* values based on a plurality of different values
for at least one of the first and second perforation intervals.
10. The method of claim 9, further comprising identifying a
position of the third fracturing location along the reservoir
interval at which a target HSAI* value exists.
11. The method of claim 5, further comprising determining a
manipulated vertical stress anisotropy (VSAI*) of the reservoir
interval, wherein VSAI* is determined according to the equation:
VSAI * = Sv - Sh * Sh * . ##EQU00006##
12. The method of claim 11, further comprising identifying a
position of the third fracturing location along the reservoir
interval at which a target VSAI* value exists.
13. A computer-based system for designing a hydraulic fracturing
operation for a hydrocarbon reservoir, comprising: a central
processing unit mounted within the computer-based system; a data
input unit connected to the central processing unit, the data input
unit receiving fracability data pertaining to the hydrocarbon
reservoir; a database connected to the central processing unit, the
database storing the fracability data for the hydrocarbon
reservoir; and a storage device connected to the central processing
unit, the storage device storing computer-readable instructions
therein, the computer-readable instructions executable by the
central processing unit to: define an anisotropy of a formation
material in the reservoir; define a heterogeneity of a formation
material in the reservoir; create a geomechanical model of at least
a portion of the reservoir based on at least the anisotropy and the
heterogeneity, wherein the geomechanical model exhibits a
prediction of at least one of pore pressure and in-situ stresses
within the portion of the reservoir; and define a wellbore path in
the geomechanical model through the portion of the reservoir.
14. The computer-based system of claim 13, wherein the
computer-readable instructions further cause the central processing
unit to identify an estimated hydraulic fracturing geometry of the
portion of the reservoir at first and second fracturing locations
along the wellbore path, the estimated hydraulic fracturing
geometry based on at least one of a geostress and a formation
material mechanical property existing at the first and second
fracturing locations.
15. The computer-based system of claim 14, wherein the
computer-readable instructions further cause the central processing
unit to: create an electronically stored fracturing geometry model
of the estimated hydraulic fracturing geometry at the first and
second fracturing locations; estimate and a first stimulated
reservoir volume of the portion of the reservoir; and add to the
electronically stored fracturing geometry model an estimated
hydraulic fracturing geometry at a third fracturing location along
the wellbore path between the first and second fracturing
locations.
16. The computer-based system of claim 15, wherein the
computer-readable instructions further cause the central processing
unit to: calculate a manipulated stress anisotropy of the portion
of the reservoir based on the addition of the estimated hydraulic
fracturing geometry at the third fracturing location; estimate a
second stimulated reservoir volume of the portion of the reservoir;
and calculate a difference between the first stimulated reservoir
volume and the second stimulated reservoir volume.
17. A computer-readable medium storing computer-readable
instructions for causing a computer to design a hydraulic
fracturing operation for a hydrocarbon reservoir, the
computer-readable instructions comprising instructions that, when
executed by a processor, cause the computer to: define an
anisotropy of a formation material in the reservoir; define a
heterogeneity of a formation material in the reservoir; create a
geomechanical model of at least a portion of the reservoir based on
at least the anisotropy and the heterogeneity, wherein the
geomechanical model exhibits a prediction of at least one of pore
pressure and in-situ stresses within the portion of the reservoir;
and define a wellbore path in the geomechanical model through the
portion of the reservoir.
18. The computer-readable medium of claim 17, wherein the
computer-readable instructions further cause the computer to
identify an estimated hydraulic fracturing geometry of the portion
of the reservoir at first and second fracturing locations along the
wellbore path, the estimated hydraulic fracturing geometry based on
at least one of a geostress and a formation material mechanical
property existing at the first and second fracturing locations.
19. The computer-readable medium of claim 18, wherein the
computer-readable instructions further cause the computer to:
create an electronically stored fracturing geometry model of the
estimated hydraulic fracturing geometry at the first and second
fracturing locations; estimate and a first stimulated reservoir
volume of the portion of the reservoir; and add to the
electronically stored fracturing geometry model an estimated
hydraulic fracturing geometry at a third fracturing location along
the wellbore path between the first and second fracturing
locations.
20. The computer-readable medium of claim 19, wherein the
computer-readable instructions further cause the computer to:
calculate a manipulated stress anisotropy of the portion of the
reservoir based on the addition of the estimated hydraulic
fracturing geometry at the third fracturing location; estimate a
second stimulated reservoir volume of the portion of the reservoir;
and calculate a difference between the first stimulated reservoir
volume and the second stimulated reservoir volume.
Description
FIELD OF INVENTION
[0001] The embodiments disclosed herein relate generally to
modeling oilfield formations, and more specifically relate to
methods and systems for designing hydraulic fracturing operations
and optimizing well production.
BACKGROUND OF INVENTION
[0002] Drilling optimization in resource shale and tight plays can
be similar in some respects to that of conventional plays. However,
differences may exist, such as with respect to time-dependent
wellbore stability due to exceptionally long horizontal well
drilling.
[0003] Developing hydrocarbon formations, such as resource shale
and/or tight plays, can be extensive and demanding, particularly
when determining a suitable multi-stage fracture (or "frac")
stimulation design. Although drilling optimization in resource
shale and tight plays may be similar to that of conventional plays
in some respects, some differences exist, such as with respect to
time-dependent wellbore stability because of relatively long
horizontal well drilling. After successful development of, e.g.,
the Barnett shale, other resource shale and tight plays have been
commercialized all over North America, and such efforts are now
extending elsewhere, such as to Central and South America, Europe,
China, Australia, and Russia. The success of resource shale and
tight plays has at least partially derived from technological
advancements during the past ten years, such as large volume
multi-stage hydraulic fracturing in horizontal completions, passive
microsiesmic monitoring and expanded use of three-dimensional
("3D") seismic of the fields. Such technological advancements in
resource shale and tight plays can present unique engineering
challenges with respect to geomechanics, such as long, horizontal
well drilling and completion methods that allow complex multi-stage
hydraulic fracture stimulation design. Horizontal drilling can
create significant wellbore stability issues, which may be
stress-induced and time-dependent, from fluid-formation
interaction.
[0004] A common approach in some areas has been to duplicate the
so-called Barnett design, such as by using a slick water fracturing
fluid with a low concentration of proppant. However, the Barnett
design can be relatively inefficient in fields other than the
Barnett shale, such as in the Haynesville, Bakken, and Eagle Ford
shales. A recent trend for developing resource shale and tight
plays has been to attain an analog field, duplicate the design
optimized in the analog field and further optimize its design by
trial and error. However, this approach can require a considerable
learning curve and associated costs to determine the optimal
multi-stage fracturing design for one or more wellbores. The
present disclosure is directed to systems and methods for
optimizing frac designs for wellbores.
BRIEF DESCRIPTION OF DRAWINGS
[0005] FIG. 1 is a schematic diagram of a drilling rig that may be
used with one of many embodiments of a hydraulic fracturing process
according to the disclosure.
[0006] FIG. 2 is a schematic perspective view illustrating one of
many embodiments of a hydraulic fracturing process according to the
disclosure.
[0007] FIG. 3 is a table illustrating relationships between
hydraulic fracture geometry, stress anisotropy and brittleness of
exemplary reservoir formations according to the disclosure.
[0008] FIG. 4 is a perspective view illustrating one of many
examples of stress overlap in an alternating sequence fracturing
operation according to the disclosure.
[0009] FIG. 5 is a flow diagram illustrating a method for
implementing one of many embodiments of a hydraulic fracturing
model according to the disclosure.
[0010] FIG. 6 is computing system that may be used with one of many
embodiments of a hydraulic fracturing process according to the
disclosure.
DETAILED DESCRIPTION OF DISCLOSED EMBODIMENTS
[0011] As an initial matter, it will be appreciated that the
development of an actual, real commercial application incorporating
aspects of the disclosed embodiments will require many
implementation-specific decisions to achieve the developer's
ultimate goal for the commercial embodiment. Such
implementation-specific decisions may include, and likely are not
limited to, compliance with system-related, business-related,
government-related and other constraints, which may vary by
specific implementation, location and from time to time. While a
developer's efforts might be complex and time-consuming in an
absolute sense, such efforts would nevertheless be a routine
undertaking for those of skill in this art having the benefits of
this disclosure. It also should be understood that the embodiments
disclosed and taught herein are susceptible to numerous and various
modifications and alternative forms. Thus, the use of a singular
term, such as, but not limited to, "a" and the like, is not
intended as limiting of the number of items. Similarly, any
relational terms, such as, but not limited to, "top," "bottom,"
"left," "right," "upper," "lower," "down," "up," "side," and the
like, used in the written description are for clarity in specific
reference to the drawings and are not intended to limit the scope
of the disclosure.
[0012] Applicants have created systems and methods for improving
production from wellbores. The systems and methods of Applicants'
disclosure can help minimize a learning curve associated with a
wellbore or formation and, in at least one embodiment, can include
providing optimal fracture design parameters based on geomechanical
analyses combined with geological, geophysical, and/or
petrophysical knowledge. In at least one embodiment, a method as
disclosed herein can include defining a well direction, defining a
fracture spacing, selecting a fracturing fluid system and
optimizing a fracture design, such as a complex multi-stage
hydraulic fracture design. A method as disclosed herein can include
determining one or more geomechanical variables for at least
partially improving production, such as well placement, horizontal
well direction, stage isolation method, stage interval, perforation
location, fracturing fluid system and fracturing proppant. In at
least one embodiment, a system can include one or more databases
integrating some or all known geomechanical information obtained
from geological, geophysical, petrophysical and laboratory data for
a field or formation. Geophysical and petrophysical analyses of
natural fractures and faults can also be included and, in at least
one embodiment, can be used for one or more stages of a fracture
design, such as for a final or other stage of a multi-stage
hydraulic fracture design, as explained in further detail
below.
[0013] The systems and methods of the present disclosure can play
an important role throughout the entire life of a reservoir, which
can, but need not, be an unconventional reservoir such as a
resource shale or tight gas/oil play. For example, as emerging
fields, such as those in Central/South America, Europe, China,
Australia, Russia and elsewhere, are being explored and placed in
well planning or development phases, the benefits of the systems
and methods disclosed herein can be realized not only for the first
well drilled in a particular location but for each well drilled in
a particular reservoir, which can be any reservoir in accordance
with a particular application. Further, the systems and methods
disclosed herein can be applied during any phase of hydrocarbon or
other operations, such as, for example, exploration phases, well
planning and development phases and other phases, such as drilling,
completion and production phases, separately or in combination, in
whole or in part.
[0014] In at least one embodiment, a method as disclosed herein can
include building one or more models for estimating properties or
attributes of a formation, such as a mechanical earth model for
modeling one or more geomechanical characteristics of a formation.
A mechanical earth model, along with the other models of this
disclosure, can be one-dimensional ("1D"), two-dimensional ("2D")
or three-dimensional ("3D"), and can be a lone model, such as a
stand-alone model, or a collective model, such as by being a part
of one or more other models, for example, an earth model, a
reservoir model, or another model. A model can comprise any data or
other information according to an application. For example, model
data can include information derived from mechanical or other
testing, such as core analyses, and can include any of numerous
characteristics associated with a formation, such as, for example,
shale anisotropy, heterogeneity, pore pressure and other variables,
such as in-situ stresses. The systems and methods of the present
disclosure, which can, but need not, be wholly or partially
implemented by way of a computer-implemented model, can be
particularly advantageous for developing unconventional fields,
including for performing drilling and completion optimization as
discussed in further detail herein.
[0015] In at least one embodiment, a method as disclosed herein can
include building a geomechanical model for a resource shale or
other play, which can include at least partially defining
anisotropy and heterogeneity of a formation and developing or
optimizing a multi-stage fracture design for the formation. A
method as disclosed herein can include developing or optimizing a
drilling phase for a formation, which can include performing one or
more analyses for determining or estimating drilling
characteristics of the formation. For example, performing a
wellbore stability analysis can include determining shear failure,
casing shear, critical stresses (e.g., critically stressed
fractures or faults) or other factors, such as time-dependence. A
method as disclosed herein can include performing a wellbore
trajectory analysis for determining the length, direction and
overall path of a wellbore. A method as disclosed herein can
include determining one or more drilling tools or properties, which
can include identifying any number of factors, such as one or more
of mud weight, mud chemistry, bit selections, trajectory, proper
landing of the lateral, data collection during drilling, casing,
etc.
[0016] A method for optimizing completion of a well can include
developing a reservoir-specific multi-stage hydraulic fracturing
design for maximizing the recovery of hydrocarbons from a
formation. In at least one embodiment, a method as disclosed herein
can include determining a horizontal or other wellbore direction,
determining fracability, determining hydraulic fracture geometry,
assessing risk of fault reactivation, determining lateral well
spacing, determining hydraulic fracturing intervals and determining
one or more fracture (i.e., perforation) locations along a
wellbore, separately or in combination, in whole or in part. In at
least one embodiment, a horizontal well direction can be determined
based on a planned or potential fracture design, e.g., longitudinal
or transverse. In at least some cases, a wellbore, such as a
horizontal wellbore, can be formed in the same or a similar
direction as the direction of a minimum horizontal stress in a
formation. For example, a well may be drilled parallel to a minimum
horizontal stress vector for achieving transverse hydraulic
fractures in a reservoir. If the stresses and stress directions
within a formation are not considered or otherwise analyzed
correctly, created hydraulic fractures can be less than optimal,
which can include developing unwanted complexities or forming in
unwanted directions (e.g., by reorienting parallel to a maximum
stress direction). This can result in unwanted effects, such as
undesired multiple fractures, creation of near-well tortuosity and
decreases in near-well fracture conductivity, which can lead to
increasing treating pressure and even inducing early screenouts. A
local direction of maximum horizontal stress to achieve proper
transverse hydraulic fractures can, in at least one embodiment, be
defined from wellbore image logs, oriented cross-dipole sonic logs
and/or micro-seismic monitoring data. Because of the inherent
differences, e.g., in anisotropy and heterogeneity, of respective
resource shale, tight reservoirs and other formations, it can be
advantageous to carry out multi-stage fracturing designs on
reservoir-specific bases. While one or more embodiments of
Applicants' disclosure are described in further detail below with
reference to an exemplary reservoir and associated orientations, a
person of ordinary skill in the art having the benefits of the
present disclosure will readily understand that such examples are
but a few of many and that the systems and methods disclosed herein
can be applied to any reservoir formation or wellbore.
[0017] Referring now to FIG. 1, an oil drilling rig 100 is shown
that may be used for hydraulic fracturing in connection with
certain aspects of the exemplary embodiments disclosed herein. The
drilling rig 100 may be used to drill a wellbore 10 in a reservoir
20 from a surface location 12, which may be a ground surface, a
drilling platform, or any other location outside of the wellbore 10
from which drilling may be controlled. The drilling rig 100 has a
drill string 26 suspended therefrom composed of a continuous length
of pipe known as drilling tubing that is made of relatively short
pipe sections 51 connected to one another. The drill string 26
typically has a bottom hole assembly attached at the end thereof
that includes a rotary drilling motor 30 connected to a drill bit
32. Drilling is typically performed using sliding drilling where
the drill bit 32 is rotated by the drilling motor 30 during
drilling, but the drilling tubing is not rotated during drilling.
The ability to perform sliding drilling, among other things, allows
the trajectory of the drill bit 32 to be controlled to thereby
drill in an angled direction relative to vertical, including a
horizontal direction.
[0018] FIG. 2 is a schematic perspective view illustrating one of
many embodiments of a hydraulic fracturing process according to the
disclosure. In at least one embodiment, a method as disclosed
herein can include determining fracture spacing, or perforation
interval, for a reservoir or wellbore, such as for at least
partially enhancing production from the reservoir based on fracture
complexity or conductivity. Finding an optimal or other perforation
interval between hydraulic fracturing stages can improve artificial
enhancement of complex network fractures and fracture conductivity
in some formations, which can include resource shale, tight plays,
or formations where a planar form of hydraulic fracture geometry is
present or anticipated. The effects of fracture spacing, i.e.,
enhancing complex network fractures and non-propped fracture
conductivity, can be universal for some or all multi-stage
fracturing techniques (e.g., sequence, zipper, etc.). However, for
illustrative purposes, FIG. 2 shows one alternating sequence
fracturing ("ASF") operation known as the "Texas two-step," which
is but one of many examples. In such a fracturing operation, the
wellbore 10 can be perforated in a plurality of locations along its
length for hydraulically fracturing the reservoir 20, which
fracturing can occur in various sequences, or stages. As shown in
the portion of wellbore 10 of FIG. 2, for example, a fracturing
operation can include three adjacent perforations for fracturing,
which are referred to herein and referenced in FIG. 2 as fracturing
Stages 1, 2 and 3 according to the order in which fracturing
occurs. Once fracturing Stages 1 and 2 are performed, hydraulic
fractures (e.g., complex planar) can be generated with limited
reservoir contact and fracture conductivity normal to the
horizontal wellbore 10. However, as a result of fracturing Stages 1
and 2 taking place, stress overlap can increase stress in one or
more directions between the two fracture stages, which can decrease
stress anisotropy between the two fracture locations. For example,
where wellbore 10 is parallel to the direction of minimal
horizontal stress in a formation (the direction of Sh in the
example of FIG. 2), fracturing Stages 1 and 2 can result in stress
overlap increasing stress in the Sh direction between the stages.
Fracturing in Stage 3 can create more complex fractures, such as
complex network fractures. In such an example, which is but one of
many, fracturing Stage 3 can create more reservoir contact and
better non-propped fracture conductivity normal to a horizontal
well. Consequently, it can be advantageous to incorporate the
effects of stress overlap into the determination of a multi-stage
hydraulic fracturing system for a reservoir in order to optimize or
at least partially improve stimulated reservoir volume ("SRV").
[0019] FIG. 3 is a table illustrating relationships between
hydraulic fracture geometry, stress anisotropy and brittleness of
exemplary reservoir formations according to the disclosure. In at
least one embodiment, a method as disclosed herein can include
defining the so-called "fracability" of a formation, which can, but
need not, occur after determining a horizontal or other well
direction for an intended multi-stage fracturing design (e.g.,
transverse). The fracability and resulting hydraulic fracture
geometry can be estimated, approximated or otherwise defined by the
stress anisotropy and brittleness of a formation, such as a
resource shale and/or tight reservoir formation. The term
fracability refers to the anticipated geometry or complexity of
fractures likely to form in a formation (which can be any
formation) as a result of hydraulic fracturing operations relative
to fracture geometry in another formation or portion of the same
formation. As illustrated in FIG. 3, in at least some cases, such
geometry can range from planar fractures to complex network
fractures. Generally, a formation having a higher fracability means
that formation is more likely to exhibit relatively complex
hydraulic fractures than a formation having a lower fracability. As
the complexity of fracturing increases from planar to complex,
reservoir contact and non-propped fracture conductivity can
increase. In at least one embodiment of the present disclosure, the
fracability and resulting hydraulic fracture geometry of a
formation can be estimated or otherwise incorporated into a method
and/or system for hydraulically fracturing a formation along a
wellbore. Factors that can control or otherwise affect the
fracability and consequent fracture geometry of a formation can
include geological stresses (e.g. in-situ stresses) and rock
(fracture) mechanical properties.
[0020] In at least one embodiment, geological stresses and
mechanical properties of a formation can be represented by
brittleness and stress anisotropy, and a method as disclosed herein
can include determining which of brittleness and stress anisotropy
is more likely to control the hydraulic fracture geometry of a
formation. For instance, high brittleness and low stress anisotropy
of a formation encourages more complexity of the hydraulic fracture
geometry (e.g., more formation contact and more production). But,
when either one of these controlling parameters is unfavorable to
the complexity of the hydraulic fracture geometry (i.e., low
brittleness or high stress anisotropy), the complexity of the
hydraulic fracture geometry diminishes significantly. That is, both
the brittleness and stress anisotropy works as the dominant
parameters defining the hydraulic fracture geometry. A method as
disclosed herein can further include determining which stress
anisotropy direction (e.g., horizontal or vertical) is more likely
to control the hydraulic fracture geometry of a formation, as
discussed below.
[0021] In at least one embodiment, a method of modeling a
multi-stage hydraulic fracturing system can include representing
the geostresses (e.g., of in-situ stresses) as stress anisotropy in
one or more of the horizontal and vertical directions. Horizontal
stress anisotropy can be defined using the following equation
(Equation 1):
HSAI = ( SH - Sh Sh ) ##EQU00001##
[0022] wherein HSAI=horizontal stress anisotropy, SH=maximum
horizontal stress and Sh=minimum horizontal stress.
[0023] Vertical stress anisotropy can be defined using the
following equation (Equation 2):
VSAI = ( Sv - Sh Sh ) ##EQU00002##
[0024] wherein VSAI=vertical stress anisotropy, Sv=vertical
overburden stress and Sh=minimum horizontal stress.
[0025] HSAI and VSAI may be expressed as unitless values or, as
another example, as percentages. A higher HSAI can indicate that
hydraulic fractures are relatively more likely to grow in the
direction of SH. A lower HSAI can indicate that hydraulic fractures
are relatively less likely to grow in the direction of SH, which
can result in more complex hydraulic fractures, such as a complex
network. Similarly, a higher VSAI can indicate that hydraulic
fractures are relatively more likely to grow in the direction of Sv
and a lower VSAI can indicate that hydraulic fractures are
relatively less likely to grow in the direction of Sv. The results
for one or more reservoir formations can be correlated or otherwise
compared and displayed, such as in a table, chart or graphical user
interface ("GUI"). Additionally, or alternatively, rock (fracture)
mechanical properties in a formation can be represented in terms of
brittleness. Brittleness can be commonly represented using a
brittleness index, or pseudo-brittleness index, based on a
combination of Young's modulus and Poisson's ratio. Generally, rock
with a higher Young's modulus and lower Poisson's ratio will be
more brittle (i.e., will have a higher brittleness index). A higher
brittleness index can indicate that hydraulic fractures have more
of a tendency to grow complex network fractures. Further, a method
as disclosed herein can include determining an optimal fracturing
fluid system, which can include determining an optimal proppant.
Fracturing fluid system and proppant selection can be decided based
on fracability or hydraulic fracture geometry type, which can be
estimated from stress anisotropy and brittleness as described
elsewhere herein. Based on the estimated hydraulic fracture
geometry type (e.g., planar to complex network), an optimal
fracturing fluid system and proppant volume, type, and size can be
selected (e.g., crosslinked gel to slick water system).
[0026] In at least one embodiment, methods and systems for
designing or implementing an improved multi-stage hydraulic
fracturing operation for increasing the SRV of a reservoir (which
can be or include any reservoir), can include determining one or
more modified, or manipulated, stress anisotropies, such as a
manipulated vertical stress anisotropy (VSAI*) or a manipulated
horizontal stress anisotropy (HSAI*). For example, manipulated
horizontal and vertical stress anisotropies can be determined for
one or more reservoir intervals between multi-stage hydraulic
fracturing stages. Like HSAI and VSAI, HSAI* and VSAI* may be
expressed as unitless values or percentages.
[0027] Manipulated horizontal stress anisotropy can be defined
using the following equation (Equation 3):
HSAI * = ( SH - Sh * Sh * ) ##EQU00003##
[0028] wherein HSAI*=manipulated horizontal stress anisotropy,
SH=maximum horizontal stress and Sh*=manipulated minimum horizontal
stress.
[0029] Manipulated vertical stress anisotropy can be defined using
the following equation (Equation 4):
VSAI * = ( Sv - Sh * Sh * ) ##EQU00004##
[0030] wherein VSAI*=manipulated vertical stress anisotropy,
Sv=vertical overburden stress and Sh*=manipulated minimum
horizontal stress.
[0031] The manipulated minimum horizontal stress Sh* can be the
increase in stress in the Sh direction caused by stress overlap due
to fracturing (e.g., hydraulic fracturing pressure and hydraulic
fracture opening). In this manner, a more accurate SRV can be
estimated for a reservoir at hand. Further, an improved multi-stage
hydraulic fracturing plan can be developed and implemented.
[0032] FIG. 4 is a perspective view illustrating one of many
examples of stress overlap in an alternating sequence fracturing
operation according to the disclosure. As described above, a stress
overlap increase can result from a third hydraulic fracture located
in between (which can be anywhere in between) two existing or other
hydraulic fractures. In at least one embodiment of the present
disclosure, stress overlap can be modeled or otherwise represented
by numerical stress analysis, which can include modeling stress
overlap or potential effects of fractures of increasing complexity
using the discrete element method or finite element analysis. In
the example shown for illustrative purposes in FIG. 4, a
brittleness index of 50 percent has been assumed, along with a
strike-slip faulting stress regime (i.e., SH>overburden>Sh).
Of course, this need not, and likely will not, always be the case,
as the brittleness, stress regime and other factors may vary from
formation to formation. In the example of FIG. 4, which is but one
of many, the numerical stress analysis shows the stress in the Sh
direction (normal to the hydraulic fracture planes P1, P2, P3)
increases approximately 55 percent, and the consequent stress
anisotropy decreases from about 95 percent to about 30 percent.
Also, the example analysis discloses the increase of treating
pressure (e.g., more than 6 percent) for the third fracture to
create a similar fracture volume. However, the treating pressure
may not account for potential complex fractures, which can be
created. That is, the actual treating pressure increase can be
higher when associated with potential complex fractures created
between the previous two fracture stages.
[0033] FIG. 5 is a flow diagram illustrating a method for
implementing one of many embodiments of a hydraulic fracturing
model according to the disclosure. In at least one embodiment, the
flow diagram can include (as generally indicated at block 500)
modeling, recommending or otherwise determining a fracture fluid
system based on geomechanical information, such as geostresses and
formation properties, and an estimation or other determination of
the type and complexity of hydraulic fractures that may occur as a
result of fracturing operations in a formation or portion of a
formation, which can be or include any formation or portion of a
formation according to an application. The flow diagram can also
include analyzing one or more geomechanical data sets, determining
one or more fracture geometries, calculating one or more values
representing brittleness, calculating one or more values
representing HSAI, calculating one or more values representing
VSAI, and recommending, outputting or otherwise determining one or
more features of a hydraulic fracturing operation. The flow diagram
can further include defining at least one of fracability and
hydraulic fracture geometry of a formation based on one or more of
brittleness and stress anisotropy.
[0034] As shown in the example embodiment of FIG. 5, which is but
one of many, a determination (block 502) may be made whether a
formation has a relatively high fracability, a medium fracability,
or a low fracability. A relatively high fracability (block 504) can
be or include a brittleness of 60-80 percent and an HSAI of 10-30
percent, and corresponding hydraulic fractures can be of the
complex network type (block 506). A relatively low fracability
(block 508) can be or include a brittleness of less than 30 percent
and an HSAI of any value, and corresponding hydraulic fractures can
be of the planar, or low complexity, type (block 510). Medium
fracability (block 512) (as well as high and low fracability)
formations can include formations having a range of brittleness and
HSAI/VSAI values. For example, a medium fracability, medium
brittleness case (block 514) can be or include a brittleness of
30-60 percent and an HSAI greater than 30 percent, and
corresponding hydraulic fractures can be of the complex planar
type. A medium fracability, high brittleness case (block 520) can
be or include a brittleness of 60-80 percent and an HSAI greater
than 100 percent, and corresponding hydraulic fractures can be of
the complex planar type. Of course, as will be understood by one of
ordinary skill having the benefits of the present disclosure, all
of the values and ranges shown and described for FIG. 5 and
elsewhere herein are for purposes of explanation and illustration
only. Such values and ranges may be the same or different for one
or more formations the subject of real-world applications, and such
values and ranges can, and likely will, differ from formation to
formation and application to application.
[0035] With continuing reference to FIG. 5, a method as disclosed
herein can include performing one or more numerical stress analyses
and defining frac spacing, such as an at least potentially optimal
frac spacing, for a formation based on one or more target stress
values for the formation. A target stress value, such as a target
HSAI* or a target VSAI*, can be or include a single value, multiple
values, a range of values, a combination thereof, or as another
example, a value that is related in some way to the foregoing. A
target stress value or set of target stress values can represent or
otherwise indicate one or more locations for perforating a
wellbore. As shown for illustrative purposes in FIG. 5, a target
stress value for a medium fracability, medium brittleness case can,
but need not, be or include an HSAI range of 10-30 percent (block
516). As another example, a target stress value for a medium
fracability, high brittleness case can, but need not, be or include
an HSAI range of 10-30 percent and a VSAI range of greater than 10
percent (block 522).
[0036] In at least one embodiment, which is but one of many, an
optimal or otherwise desirable frac spacing can be determined by
defining two or more perforation locations having frac spacing(s)
there between, modeling a perforation and fracture complexity at
one of more of the perforation locations, modeling the resulting
production, and repeating the foregoing steps for different
perforation locations and frac spacing. The production models can
be compared and perforation locations and frac spacing can be
determined for a particular formation at hand, which can be any
formation (including any portion of a formation). For example,
perforation locations and frac spacing can be recommended or chosen
for a physical formation according to which production model
predicts the most desirable results, which can be or include any
result, such as, but not limited to, the greatest production.
Additionally, or alternatively, a method as disclosed herein can
include determining a frac fluid system for use with the formation,
which can include a frac fluid alone or a fluid in combination with
one or more proppants. As shown in the exemplary embodiment of FIG.
5, which is but one of many, a low viscosity, fine proppant frac
fluid system in combination with relatively large frac spacing
(e.g., slick-water fluid, 100 mesh proppant, and .gtoreq.300 feet
frac spacing) can be advantageous for one or more high fracability,
complex network fracture formations, whereas a high viscosity,
coarse proppant frac fluid system (e.g., cross-linked gel fluid,
20/40 mesh proppant) can be advantageous for one or more low
fracability, planar fracture formations. In at least one
embodiment, a method as disclosed herein can include determining
frac spacing based on the quality of the reservoir formation, such
as by simulating the reservoir as a computer model or
otherwise.
[0037] In medium fracability, complex planar fracture formations,
other frac fluid systems and frac spacings can be advantageous. As
will be understood by a person of ordinary skill in the art having
the benefits of the present disclosure, one or more of the systems
and methods disclosed herein can include estimating or otherwise
determining an optimized or at least partially improved frac fluid
system or frac spacing for a formation based on improved
fracability or production estimations derived from a comparison of
two or more model iterations constructed according to the
disclosure, separately or in combination, in whole or in part
(generally indicated at block 518 and 524). More specifically, many
resource shale or tight formations have medium fracability, which
can include having medium brittleness (e.g., 30-60 percent) and
medium to high HSAI (e.g., 30-100 percent or greater than 100
percent), or high brittleness (e.g., 60-70 percent) and high HSAI
(e.g., greater than 100 percent), separately or in combination, in
whole or in part. For at least some medium-fracability formations,
a hybrid frac fluid system can be used, which can include starting
with a low viscosity, fine proppant frac fluid and ending up with a
high viscosity, coarse proppant frac fluid. However, the
fracability of such formations can be improved or increased and the
consequent complexity of hydraulic fractures can be enhanced
artificially, and in at least one embodiment, the systems and
methods disclosed herein can include at least partially improving
the enhancement and estimating a magnitude of such enhancement or
improvement.
[0038] With continuing reference to FIG. 5, in at least one
embodiment, a method as disclosed herein can include decreasing
frac spacing in a multi-stage hydraulic fracturing design (e.g.,
from 300 feet to 150 feet) and increasing stresses in a formation
between two or more hydraulic fractures, such as by creating or
increasing stress overlap. A method as disclosed herein can include
increasing stress overlap in a direction normal or about normal to
one or more hydraulic fractures (i.e., increasing Sh) and
decreasing HSAI in at least a portion of the formation (see
Equation 1). A method as disclosed herein can include estimating a
decrease in HSAI, which can include performing a numerical stress
analysis for at least a portion of the formation (see, e.g., FIG.
4), such as an analysis based on data representing one or more of
geostresses, formation rock properties and net pressure, separately
or in combination, in whole or in part. Such data can, but need
not, be obtained from a conventional single hydraulic fracture
operation(s). In at least one embodiment, a method as disclosed
herein can include determining or identifying a target HSAI for a
formation, modeling the formation, and iteratively or otherwise
determining at least one of a frac spacing and a frac fluid system
that at least partially achieves the target HSAI. A method as
disclosed herein can include producing a set of instructions for
achieving the target HSAI and hydraulically fracturing a wellbore
according to the instructions, which can include at least one of
initially hydraulically fracturing a wellbore and modifying a prior
hydraulic fracturing system for a wellbore, such as by changing a
frac fluid, proppant or spacing. In at least one embodiment, a
method as disclosed herein can include limiting or otherwise
controlling a change to Sh for maintaining VSAI at or near a value
or within a range of values (see Equations 1, 2). For example, in
some formations, such as in a medium-frac ability formation having
high brittleness and high HSAI, a fracturing configuration based on
a relatively low target HSAI (e.g., 10-30 percent) can result in
the generation of horizontal or other fractures that may be
unintended or undesirable. In such cases, or in other applications,
a method according to the disclosure can include determining one or
more limits for Sh for maintaining a VSAI greater than zero (e.g.,
10 percent or another value greater than zero). However, this need
not be the case, and alternatively, or collectively, an Sh value
can result in a VSAI less than or equal to zero.
[0039] One or more other embodiments of the systems and methods of
the present disclosure will now be described, which systems and
methods can be combined, in whole or in part, with those described
above. In at least one embodiment, a method as disclosed herein can
include building a geomechanical model of a formation, performing a
petrophysical fracture analysis of the formation, performing a
hydraulic fracturing design for one or more fractures along a
wellbore through or in the formation, performing a stress analysis
of the formation based on one or more fractures and performing a
reservoir simulation of production from the formation via the
wellbore as fractured. Hydrocarbon formations can exhibit various
types or shapes of fractures upon being subjected to hydraulic
fracturing operations. As describe above, for example, depending on
the formation and one or more of the other factors described herein
(or other factors that may be known in the art), hydraulically
fractured formations can exhibit simple fractures, complex
fractures, complex fractures with fissure openings and others, such
as complex fracture networks comprised of numerous fractures, which
can include any type of fractures in fluid communication with one
another, in whole or in part. The types of fractures in a
particular formation or reservoir can relate to one or more
characteristics of the formation and/or of the materials present in
the formation. These characteristics can include, for example,
stress anisotropy and brittleness, among others, such as
mineralogy, rock strength, porosity, permeability, content of clay
or other types of earth, total organic carbon ("TOC") content,
thermal maturity, gas content, gas-in-place, organic content and
organic maturity, separately or in combination, in whole or in
part. The attributes and characteristics of a formation, and the
types of fractures expected to result from hydraulic fracturing of
such a formation, can affect one or more considerations when
considering potential fracturing approaches, such as, for example,
a completion focus. Other factors that can influence frac design
can include the results of testing performed on a reservoir or
formation, such as log and core analyses, which, if present, can be
incorporated into one or more of the systems and methods disclosed
herein. In at least one embodiment, a method as disclosed herein
can include determining, estimating or defining, which can include
modeling, any of horizontal or other well direction, the number of
perforation clusters, the spacing between perforation clusters, the
location for each perforation cluster, the type of frac fluid and
the injection rate of frac fluid, among other factors, such as the
kind of proppant and the amount of proppant.
[0040] The systems and methods of the present disclosure can be
used during any phase of development of a formation, which can be
any formation according to a particular application. For example,
the systems and methods of the present disclosure can be used
during exploration phases, well planning phases, well development
phases and other phases, such as drilling optimization or
completion optimization, separately or in combination, in whole or
in part. In at least one embodiment, a method as disclosed herein
can include building a geomechanical model, such as a 1D, 2D or 3D
model, performing a core analysis (e.g., for determining anisotropy
and/or heterogeneity of one or more materials, such as shale),
performing a pore pressure analysis, performing an in-situ stress
analysis and estimating one or more mechanical properties of a
formation. In at least one embodiment, a method as disclosed herein
can include performing a drilling optimization analysis, which can,
but need not, include performing a wellbore stability analysis for
determining shear failure, time dependency, casing shear,
critically stressed fractures or faults or other factors or
parameters. A drilling optimization analysis can, but need not,
include performing a wellbore trajectory analysis for determining
(whether by certainty or estimation) the trajectory of one or more
wellbores. Such analyses can result in the identification of one or
more parameters for an optimal drilling design, such as mud weight,
mud chemistry, trajectory or other factors, such as casing type. In
at least one embodiment, a method as disclosed herein can include
performing a completion optimization analysis, such as for
determining a reservoir-specific, multi-stage or other hydraulic
fracturing design. For example, such a method as disclosed herein
can include determining horizontal wellbore direction, defining
fracability, determining fracture geometry, assessing the risk of
fault reactivation, determining optimal lateral well spacing and
other steps, such as, for example, determining hydraulic fracture
interval (i.e., spacing) and pinpointing or otherwise determining
one or more optimal hydraulic fracture (i.e., perforation)
locations along one or more wellbores. As used herein, the terms
formation and reservoir are synonymous unless otherwise indicated,
and both terms can include an entire formation or a portion of a
formation.
[0041] In at least one embodiment, a method as disclosed herein can
include creating, processing or otherwise analyzing a series of
models, which can include 1D, 2D and/or 3D models, and estimating,
recommending or otherwise identifying an optimal (or at least
potentially advantageous in one or more ways) hydraulic fracturing
("HF") operation or "frac design" for a wellbore, which can include
a single- or multi-stage frac design. For example, a method as
disclosed herein can include analyzing a drilling model, analyzing
a stress model, analyzing a basin model, analyzing a seismic model
and analyzing one or more other models, such as a geographical
(e.g., regional, local or otherwise) scale model, a numerical
stress model or a thermal model, separately or in combination, in
whole or in part. A method as disclosed herein can include modeling
and analyzing any of numerous factors associated with one or more
formations or wellbores, such as salt content, production,
injection, sanding, geothermal and/or other factors, such as one or
more of the factors or parameters described elsewhere herein. In at
least one embodiment, one or more existing software applications
can be used to develop or otherwise analyze one or more of the
models described herein, such as, for example, Drillworks
Predict.RTM., Geostress.RTM., Presage.RTM., or Drillworks 3D.RTM..
However, this need not be the case, and alternatively, or
collectively, one or more software applications can be
independently developed for embodying the systems and methods of
the present disclosure, separately or in combination with one
another or one or more existing applications.
[0042] In at least one embodiment, a method as disclosed herein can
include inputting, considering, processing or otherwise analyzing
data associated with one or more formations or wellbores, which can
include actual data collected, estimated data, predicted data,
calculated data, and/or any other data according to a particular
application, such as known data from operations that have taken or
are taking place within or for one or more other formations or
wellbores. For example, formation data can be or include data or
other information gathered from wireline operations,
logging-while-drilling ("LWD") operations, core tests and other
testing or analyses. In at least one embodiment, a method as
disclosed herein can include analyzing formation data regarding any
one or more of lithology (e.g., gamma ray), resistivity, pore
pressure, sonic data (e.g., oriented crossed-dipole), mechanical
and other rock properties, density, temperature, pressure,
overburden, wellbore stability, formation images, formation
stresses, natural fractures, uni- or multi-axial compression,
compression considering shale or other anisotropy (e.g., normal and
parallel to bedding), Young's modulus (e.g., vertical and
horizontal), Poisson's ratio (e.g., vertical and horizontal),
mineralogy (e.g., x-ray detraction ("XRD"), time-dependent wellbore
stability, fluid-rock interaction (e.g., capillary suction time
("CST") testing, proppant embedment, Brinnell hardness, hole size,
well depth, shear, tensile forces, spalling, formation material(s),
breakout, drilling induced fractures (e.g., tensile fractures),
stress regions, world stress maps, in-situ stress regimes (e.g.,
extensional regimes, strike-slip regimes, compressional regimes),
drilling instability, wellbore instability, faulting (e.g., normal
faulting, strike slip faulting, reverse faulting), instabilities
with and/or without consideration of anisotropy (e.g., shale
anisotropy) and/or hole cleaning, flow rates, fracture size, fluid
type, proppant concentration, fluid volume, proppant volume, number
of fracture stages, effective confining pressure, effective mean
stress, layering, shale or other formation material quality,
trajectory, efficiency, separately or in combination, in whole or
in part.
[0043] In at least one embodiment, a method as disclosed herein can
include creating a seismic interval velocity model of a formation,
creating a pore pressure gradient model of a formation, creating an
overburden gradient model of a formation and creating a fracture
gradient model of a formation. A method as disclosed herein can
include analyzing in-situ stresses, which can include determining
an applicable stress regime, determining an applicable fault type
and determining one or more effects of stresses and faults on one
or more wellbores. A method as disclosed herein can include
determining the manner in which wellbore stability can vary
according to wellbore location and position, which can include
determining a most stable direction, a least stable direction and
relative stabilities in one or more other directions. A method as
disclosed herein can include determining a zero stress anisotropy
direction in a formation and how or whether such a direction
various, such as according to one or more stresses in one or more
stress directions within the formation. A method as disclosed
herein can include modeling, predicting or otherwise analyzing the
complexity of one or more hydraulic or other fractures based on
in-situ or other stresses present in a formation. A system can
include a dataset representing one or more HF factors, such as a
dataset relating fracture geometry to one or more parameters that
can control or otherwise affect fracture geometry resulting from
hydraulic fracturing. For example, a dataset can include
information regarding fracture geometry type, stress anisotropy,
brittleness, completion focus and one or more reservoirs, and can
relate or compare such information as it relates to the one or more
reservoirs. In at least one embodiment, a dataset can represent the
relative presence or magnitude of reservoir contact, fracture
conductivity and natural fractures among one or more formations,
such as based on one or more attributes of the formation(s), e.g.,
brittleness, Young's modulus, Poisson's ratio and/or one or more of
the other factors described herein.
[0044] In at least one embodiment, a method as disclosed herein can
include defining a location, spacing, number, direction and
sequence of perforations for one or more wellbores, analyzing the
SRV, changing one or more of the foregoing factors, re-analyzing
the SRV for the one or more wellbores, and determining the
differences in the SRV (or other characteristics) in light of the
changes. A method as disclosed herein can include performing these
steps manually, automatically or otherwise, separately or in
combination, in whole or in part, and can include performing any of
the steps in any order and in any number of iterations. A method as
disclosed herein can include identifying one or more parameters
that can control HF geometry in a formation, which can be or
include any of the parameters and other factors described herein. A
method as disclosed herein can include selecting a frac fluid and
proppant system for a formation based on one or more controlling
parameters of HF geometry within the formation. A method as
disclosed herein can include monitoring any of the parameters and
other factors described herein during production operations and
changing one or more aspects of a frac design for a formation. In
at least one embodiment, which is but one of many, a method as
disclosed herein can include modeling or otherwise analyzing the
characteristics of a reservoir over a distance or length of a
wellbore, which can be any distance according to a particular
application. The method can include analyzing the stress anisotropy
and brittleness index (or fracability) of that portion of the
reservoir, comparing the foregoing information, and identifying one
or more locations at which to perforate the formation for promoting
(or at least potentially promoting) the best possible production
from that formation. The method can include determining a
fracturing system for use in the area(s) analyzed. In this manner,
at least partially optimized production and minimized costs can be
achieved by combining petrophysical reservoir characteristics and
geomechanical fracability analyses along one or more horizontal
wells in or through a formation. A method for optimizing production
from a well can include combining petrophysical and geomechanical
analyses for determining preferred hydraulic fracturing locations,
directions and sequences. Geophysical and petrophysical analyses on
natural fractures and faults can also be used, for example, for
designing final or other multi-stage hydraulic fracture
systems.
[0045] In at least one embodiment, a system for modeling a
multi-stage fracturing operation can be or include a computerized
model of one or more of any of wellbores, formations, stresses,
stress anisotropies, brittleness, hydraulic fractures, perforation
types, perforation spacings, fracturing fluids, proppants, drilling
equipment, pipes, drilling fluids and the other factors, variable
and attributes described herein. In at least one embodiment, a
system for modeling a multi-stage fracturing operation can be
implemented, in whole or in part, using software, such as one or
more of the software applications described above. The software can
include, for example, routines, programs, objects, components, and
data structures for performing particular tasks or implementing
particular data types, such as abstract or other data types. The
interface(s) and implementations of the present disclosure may
reside on a suitable computer system (which can be any computer or
system of computers required by a particular application) having
one or more computer processors, such as an Intel Xeon 5500, and
computer readable storage, which may be accessible through a
variety of memory media, including semiconductor memory, hard disk
storage, CD-ROM and other media now known or future developed. One
or more embodiments of the disclosure may also cooperate with one
or more other system resources, such as Oracle.RTM. Enterprise, and
suitable operating system resources, such as Microsoft.RTM.
Windows.RTM., Red Hat.RTM. or others, separately or in
combination.
[0046] One or more embodiments of Applicants' disclosure can
cooperate with other databases and resources available to a
multi-stage fracturing system or network. For example, at least one
implementation may cooperate with one or more databases, such as a
database accessible on the same computer, over a local data bus, or
through a network connection. The network connection may be a
public network, such as the Internet, a private network, such as a
local area network ("LAN"), or some combination of networks. Those
skilled in the art having the benefits of Applicants' disclosure
will appreciate that one or more embodiments of the disclosure may
be implemented in a variety of computer-system configurations, or
computer architectures. It will be appreciated that any number of
computer systems and computer networks are acceptable for use in
embodiments of the disclosure. Still further embodiments may be
implemented in distributed-computing environments, such as where
tasks are performed by remote-procressing devices that may be
linked through a communications network. In a distributed-computing
environment, program modules may, but need not, be located in both
local and remote computer-storage media, including memory storage
devices or other media.
[0047] One or more embodiments of the disclosure can be stored on
computer readable media, such as one or more hard disk drives,
DVDs, CD ROMs, flash drives, or other semiconductor, magnetic or
optically readable media, separately or in combination, in whole or
in part. These computer storage media may carry computer readable
instructions, data structures, program modules and other data
representing one or more embodiments of the disclosure, or portions
thereof, for loading and execution by an implementing computer
system. Although one or more other internal components of a
suitable computing system may not be specifically shown or
described herein, those of ordinary skill in the art will
appreciate that such components and their interconnection and
operation are well known.
[0048] In at least one embodiment of the disclosure, data
federation or other techniques can be used to combine information
from one or more databases, such as information regarding one or
more formations or other characteristics thereof, separately or in
combination with information from one or more other sources (e.g.,
those described elsewhere herein), into a system for optimizing a
model of a hydraulic fracturing system or design. This can be
accomplished according to a computer implemented process that
synchronizes (e.g., periodically, continuously or otherwise) the
model with, for example, the most current information about a
physical oilfield formation available at a particular time or times
of interest to a user. There are many sources of information that
may be used to provide information into an optimized fracturing
model according to embodiments of the disclosure. For example, the
database(s) used by Landmark Graphics Corporation's OpenWells.RTM.
Engineering Data Model ("EDM"), those used by Peloton's
Wellview.RTM. (MasterView), or other well drilling operational
databases, may provide data such as the latitude and longitude of
wells in a formation(s). Also, or alternatively, a system according
to the disclosure can include formation information from one or
more geographical information systems ("GIS"), public data sources,
or other sources, such as databases including information regarding
materials (e.g., material factors, types or properties), component
sizes (e.g., diameters, lengths, etc.), friction factors, or
variable described elsewhere herein. Of course, any or all data
from a particular source can be considered or otherwise used as
required or desired for a particular application of an embodiment,
in whole or in part, separately or in combination, and in at least
some embodiments may be used to obtain other information that may
not be immediately available in a particular form or format. For
example, if desired formation information is not explicitly
included in a source database, such information can be determined
from other information in at least some cases.
[0049] FIG. 6 illustrates an exemplary system 600 that may be used
in performing all or a lease portion of the well fracturing design
and modeling process described herein. The exemplary system 600 may
be a conventional workstation, desktop, or laptop computer, or it
may be a custom computing system 600 developed for a particular
application. In a typical arrangement, the system 600 includes a
bus 602 or other communication pathway for transferring information
among other components within the system 600, and a CPU 604 coupled
with the bus 602 for processing the information. The system 600 may
also include a main memory 606, such as a random access memory
(RAM) or other dynamic storage device coupled to the bus 602 for
storing computer-readable instructions to be executed by the CPU
604. The main memory 606 may also be used for storing temporary
variables or other intermediate information during execution of the
instructions by the CPU 604.
[0050] The system 600 may further include a read-only memory (ROM)
608 or other static storage device coupled to the bus 602 for
storing static information and instructions for the CPU 604. A
computer-readable storage device 610, such as a nonvolatile memory
(e.g., Flash memory) drive or magnetic disk, may be coupled to the
bus 602 for storing information and instructions for the CPU 604.
The CPU 604 may also be coupled via the bus 602 to a display 612
for displaying information to a user. One or more input devices
614, including alphanumeric and other keyboards, mouse, trackball,
cursor direction keys, and so forth, may be coupled to the bus 602
for communicating information and command selections to the CPU
604. A communications interface 616 may be provided for allowing
the horizontal well design system 600 to communicate with an
external system or network.
[0051] In accordance with the exemplary disclosed embodiments, one
or more hydraulic fracturing modeling applications 618, or the
computer-readable instructions therefor, may also reside on or be
downloaded to the storage device 610 for execution. In general, the
one or more applications 618 are or include one or more computer
programs that may be executed by the CPU 604 and/or other
components to allow users to perform some or all the hydraulic
fracturing design and modeling process described herein. Such
applications 618 may be implemented in any suitable computer
programming language or software development package known to those
having ordinary skill in the art, including various versions of C,
C++, FORTRAN, and the like.
[0052] Accordingly, as set forth above, the embodiments disclosed
herein may be implemented in a number of ways. In general, in one
aspect, the exemplary embodiments include a computer-implemented
method of designing a hydraulic fracturing operation for a
hydrocarbon reservoir. The method comprises defining an anisotropy
of a formation material in the reservoir, defining a heterogeneity
of a formation material in the reservoir, and creating, in computer
readable storage, an electronically stored geomechanical model of
at least a portion of the reservoir based on at least the
anisotropy and the heterogeneity, wherein the geomechanical model
exhibits a prediction of at least one of pore pressure and in-situ
stresses within the portion of the reservoir. The method also
comprises defining a wellbore path in the geomechanical model
through the portion of the reservoir, and identifying an estimated
hydraulic fracturing geometry of the portion of the reservoir at
first and second fracturing locations along the wellbore path,
wherein the estimated hydraulic fracturing geometry is based on at
least one of a geostress and a formation material mechanical
property existing at the first and second fracturing locations. The
method additionally comprises creating, in computer readable
storage, an electronically stored fracturing geometry model of the
estimated hydraulic fracturing geometry at the first and second
fracturing locations, estimating a first stimulated reservoir
volume of the portion of the reservoir, and adding to the
electronically stored fracturing geometry model an estimated
hydraulic fracturing geometry at a third fracturing location along
the wellbore path between the first and second fracturing
locations. The method further comprises calculating a manipulated
stress anisotropy of the portion of the reservoir based on the
addition of the estimated hydraulic fracturing geometry at the
third fracturing location, estimating a second stimulated reservoir
volume of the portion of the reservoir; and calculating a
difference between the first stimulated reservoir volume and the
second stimulated reservoir volume.
[0053] In some embodiments, the method may further comprise any one
of the following features individually or any two or more of these
features in combination, including: changing at least one variable
within the fracturing geometry model, recalculating the manipulated
stress anisotropy, and estimating a third stimulated reservoir
volume of the portion of the reservoir; the at least one variable
is selected from the group consisting of well interval, perforation
interval, perforation order and a combination thereof; performing a
numerical stress analysis of a reservoir interval between the first
and second fracturing locations; the third fracturing location is
disposed within a reservoir interval and located a first
perforation interval from the first fracturing location and a
second perforation interval from the second fracturing location,
and wherein the method further comprises determining a change in
stress in one or more directions within the reservoir interval;
determining a change in treating pressure based on the change in
stress; determining a likelihood that hydraulic fracturing at the
third fracturing location will cause fractures of increased
complexity in the reservoir interval between the first and second
fracturing locations; determining a manipulated horizontal stress
anisotropy (HSAI*) of the reservoir interval based on the first and
second perforation intervals, wherein HSAI* is determined according
to the equation: HSAI *=(SH-Sh *)/(Sh*); determining a plurality of
HSAI* values based on a plurality of different values for at least
one of the first and second perforation intervals; identifying a
position of the third fracturing location along the reservoir
interval at which a target HSAI* value exists; determining a
manipulated vertical stress anisotropy (VSAI*) of the reservoir
interval, wherein VSAI* is determined according to the equation:
VSAI *=(Sv-Sh *)/(Sh*); and identifying a position of the third
fracturing location along the reservoir interval at which a target
VSAI* value exists
[0054] In general, in another aspect, the exemplary embodiments
include a computer-based system for designing a hydraulic
fracturing operation for a hydrocarbon reservoir. The
computer-based system comprises a central processing unit mounted
within the computer-based system, a data input unit connected to
the central processing unit, the data input unit receiving
fracability data pertaining to the hydrocarbon reservoir, a
database connected to the central processing unit, the database
storing the fracability data for the hydrocarbon reservoir, and a
storage device connected to the central processing unit, the
storage device storing computer-readable instructions therein. The
computer-readable instructions are executable by the central
processing unit to perform the method of designing a hydraulic
fracturing operation for a hydrocarbon reservoir as substantially
described above.
[0055] In general, in yet another aspect, the exemplary embodiments
include a computer-readable medium storing computer-readable
instructions for causing a computer to design a hydraulic
fracturing operation for a hydrocarbon reservoir. The
computer-readable instructions comprises instructions for causing
the computer to perform the method of designing a hydraulic
fracturing operation for a hydrocarbon reservoir as substantially
described above.
[0056] The role of the systems and methods of the present
disclosure can be continuous throughout the life of an
unconventional or other reservoir, and can be focused during
exploration, well planning and development phases, such as when
optimizing multi-stage hydraulic fracturing design. The systems and
methods disclosed herein can enhance hydrocarbon production and
reduce costs by minimizing learning curves associated with one or
more formations, such as emerging resource shale and tight
plays.
[0057] Other and further embodiments utilizing one or more aspects
of the systems and methods described above can be devised without
departing from the spirit of Applicants' disclosures. For example,
the systems and methods disclosed herein can be used alone or to
form one or more parts of another modeling, simulation or other
analysis system. Further, the various methods and embodiments of
the workflow system can be included in combination with each other
to produce variations of the disclosed methods and embodiments.
Discussion of singular elements can include plural elements and
vice-versa. References to at least one item followed by a reference
to the item may include one or more items. Also, various aspects of
the embodiments can be used in conjunction with each other. Unless
the context requires otherwise, the word "comprise" and variations
such as "comprises" or "comprising" should be understood to imply
the inclusion of at least the stated element or step or group of
elements or steps or equivalents thereof, and not the exclusion of
a greater numerical quantity or any other element or step or group
of elements or steps or equivalents thereof. The order of steps can
occur in a variety of sequences unless otherwise specifically
limited. The various steps described herein can be combined with
other steps, interlineated with the stated steps, and/or split into
multiple steps. Similarly, elements have been described
functionally and can be embodied as separate components or can be
combined into components having multiple functions.
[0058] As will be appreciated by those skilled in the art, one or
more embodiments of the present disclosure may be embodied as a
method, data processing system, or computer program product.
Accordingly, at least one embodiment may take the form of an
entirely hardware embodiment, an entirely software embodiment, or
an embodiment combining software and hardware aspects. Furthermore,
at least one embodiment may be a computer program product on a
computer-usable storage medium having computer readable program
code on the medium. Any suitable computer readable medium may be
utilized including, but not limited to, static and dynamic storage
devices, hard disks, optical storage devices, and magnetic storage
devices.
[0059] At least one embodiment may be described herein with
reference to flowchart illustrations of methods, systems, and
computer program products according to the disclosure. It will be
understood that each block of a flowchart illustration, and
combinations of blocks in flowchart illustrations, can be
implemented by computer program instructions. These computer
program instructions may be provided to a processor of a general
purpose computer, special purpose computer, or other programmable
data processing apparatus to produce a machine, such that the
instructions, which can execute via a processor of a computer or
other programmable data processing apparatus, can implement the
functions specified in the flowchart block or blocks, separately or
in combination, in whole or in part.
[0060] The computer program instructions may be stored in a
computer-readable memory that can direct a computer or other
programmable data processing apparatus to function in a particular
manner, such that the instructions stored in the computer-readable
memory result in an article of manufacture including instructions
which can implement the function(s) specified in the flowchart
block or blocks. The computer program instructions may be loaded
onto a computer or other programmable data processing apparatus to
cause a series of operational steps to be performed on the computer
or other programmable apparatus to produce a computer implemented
process such that the instructions which execute on the computer or
other programmable apparatus provide steps for implementing the
functions specified in the flowchart block or blocks.
[0061] While the disclosed embodiments have been described with
reference to one or more particular implementations, those skilled
in the art will recognize that many changes may be made thereto
without departing from the spirit and scope of the description and
that obvious modifications and alterations to the described
embodiments are available. Accordingly, each of these embodiments
and obvious variations thereof is contemplated as falling within
the spirit and scope of the disclosure and, in conformity with the
patent laws, Applicants intend to fully protect all such
modifications and improvements that come within the scope or range
of equivalents of the following claims.
* * * * *