US20180094514A1

US20180094514A1 - Shale geomechanics for multi-stage hydraulic fracturing optimization in resource shale and tight plays

Info

Publication number: US20180094514A1
Application number: US15/562,528
Authority: US
Inventors: Junghun LEEM; Juan J. REYNA
Original assignee: Landmark Graphics Corporation
Current assignee: Landmark Graphics Corp
Priority date: 2015-04-30
Filing date: 2015-04-30
Publication date: 2018-04-05
Also published as: NO20171501A1; GB2554194A; GB201715356D0; AU2015392975A1; FR3035674A1; WO2016175844A1; CA2980717A1

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.

Description

FIELD OF INVENTION

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

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.
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.
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

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.

FIG. 2 is a schematic perspective view illustrating one of many embodiments of a hydraulic fracturing process according to the disclosure.

FIG. 3 is a table illustrating relationships between hydraulic fracture geometry, stress anisotropy and brittleness of exemplary reservoir formations according to the disclosure.

FIG. 4 is a perspective view illustrating one of many examples of stress overlap in an alternating sequence fracturing operation according to the disclosure.

FIG. 5 is a flow diagram illustrating a method for implementing one of many embodiments of a hydraulic fracturing model according to the disclosure.

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

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.
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.
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.
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.
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.
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.
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.
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”).
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.
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.
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):
$HSAI = (\frac{SH - Sh}{Sh})$
wherein HSAI=horizontal stress anisotropy, SH=maximum horizontal stress and Sh=minimum horizontal stress.
Vertical stress anisotropy can be defined using the following equation (Equation 2):
$VSAI = (\frac{Sv - Sh}{Sh})$
wherein VSAI=vertical stress anisotropy, Sv=vertical overburden stress and Sh=minimum horizontal stress.
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).
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.
Manipulated horizontal stress anisotropy can be defined using the following equation (Equation 3):
${HSAI}^{*} = (\frac{SH - {Sh}^{*}}{Sh *})$
wherein HSAI*=manipulated horizontal stress anisotropy, SH=maximum horizontal stress and Sh*=manipulated minimum horizontal stress.
Manipulated vertical stress anisotropy can be defined using the following equation (Equation 4):
${VSAI}^{*} = (\frac{Sv - {Sh}^{*}}{Sh *})$
wherein VSAI*=manipulated vertical stress anisotropy, Sv=vertical overburden stress and Sh*=manipulated minimum horizontal stress.
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.
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.
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.
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.
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).
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 ≧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.
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.
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.
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.
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.
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®, Geostress®, Presage®, or Drillworks 3D®. 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.
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.
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.
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.
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® Enterprise, and suitable operating system resources, such as Microsoft® Windows®, Red Hat® or others, separately or in combination.
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.
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.
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® Engineering Data Model (“EDM”), those used by Peloton's Wellview® (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.
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.
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.
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.
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.
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
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.
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.
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.
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.
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.
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.
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.
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.

Claims

What is claimed is:

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}^{*} = \frac{SH - {Sh}^{*}}{Sh *} .

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}^{*} = \frac{Sv - {Sh}^{*}}{Sh *} .

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;

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:

20. The computer-readable medium of claim 19, wherein the computer-readable instructions further cause the computer to: