CA3194382A1 - Method and system for simulating hydraulic fracturing in a naturally fractured reservoir - Google Patents
Method and system for simulating hydraulic fracturing in a naturally fractured reservoirInfo
- Publication number
- CA3194382A1 CA3194382A1 CA3194382A CA3194382A CA3194382A1 CA 3194382 A1 CA3194382 A1 CA 3194382A1 CA 3194382 A CA3194382 A CA 3194382A CA 3194382 A CA3194382 A CA 3194382A CA 3194382 A1 CA3194382 A1 CA 3194382A1
- Authority
- CA
- Canada
- Prior art keywords
- hydraulic fracturing
- material property
- fluid
- fracture
- reservoir
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Pending
Links
- 238000000034 method Methods 0.000 title claims abstract description 65
- 239000000463 material Substances 0.000 claims abstract description 61
- 230000000977 initiatory effect Effects 0.000 claims abstract description 17
- 239000011159 matrix material Substances 0.000 claims abstract description 14
- 239000011435 rock Substances 0.000 claims abstract description 14
- 239000012530 fluid Substances 0.000 claims description 70
- 238000002347 injection Methods 0.000 claims description 36
- 239000007924 injection Substances 0.000 claims description 36
- 238000004458 analytical method Methods 0.000 claims description 29
- 238000004590 computer program Methods 0.000 claims description 21
- 238000013500 data storage Methods 0.000 claims description 17
- 230000035699 permeability Effects 0.000 claims description 13
- 206010017076 Fracture Diseases 0.000 description 132
- 208000010392 Bone Fractures Diseases 0.000 description 113
- 238000004088 simulation Methods 0.000 description 41
- 238000010586 diagram Methods 0.000 description 24
- 230000003993 interaction Effects 0.000 description 20
- 238000006073 displacement reaction Methods 0.000 description 15
- 238000013459 approach Methods 0.000 description 9
- 230000007420 reactivation Effects 0.000 description 9
- 238000011439 discrete element method Methods 0.000 description 6
- 230000006399 behavior Effects 0.000 description 4
- 230000000704 physical effect Effects 0.000 description 4
- 230000001965 increasing effect Effects 0.000 description 3
- 239000011148 porous material Substances 0.000 description 3
- 230000004075 alteration Effects 0.000 description 2
- 230000006870 function Effects 0.000 description 2
- 238000013178 mathematical model Methods 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 230000003936 working memory Effects 0.000 description 2
- 208000006670 Multiple fractures Diseases 0.000 description 1
- 230000004913 activation Effects 0.000 description 1
- 230000015572 biosynthetic process Effects 0.000 description 1
- 238000004422 calculation algorithm Methods 0.000 description 1
- 238000004364 calculation method Methods 0.000 description 1
- 239000004020 conductor Substances 0.000 description 1
- 239000000470 constituent Substances 0.000 description 1
- 238000000354 decomposition reaction Methods 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000010339 dilation Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- 230000001939 inductive effect Effects 0.000 description 1
- 230000015654 memory Effects 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 238000005192 partition Methods 0.000 description 1
- 238000012502 risk assessment Methods 0.000 description 1
Classifications
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
- G06F30/00—Computer-aided design [CAD]
- G06F30/20—Design optimisation, verification or simulation
- G06F30/23—Design optimisation, verification or simulation using finite element methods [FEM] or finite difference methods [FDM]
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V20/00—Geomodelling in general
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
- E21B2200/20—Computer models or simulations, e.g. for reservoirs under production, drill bits
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/60—Analysis
- G01V2210/64—Geostructures, e.g. in 3D data cubes
- G01V2210/646—Fractures
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/60—Analysis
- G01V2210/66—Subsurface modeling
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/60—Analysis
- G01V2210/66—Subsurface modeling
- G01V2210/663—Modeling production-induced effects
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
- G06F2113/00—Details relating to the application field
- G06F2113/08—Fluids
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
- G06F2119/00—Details relating to the type or aim of the analysis or the optimisation
- G06F2119/02—Reliability analysis or reliability optimisation; Failure analysis, e.g. worst case scenario performance, failure mode and effects analysis [FMEA]
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
- G06F2119/00—Details relating to the type or aim of the analysis or the optimisation
- G06F2119/14—Force analysis or force optimisation, e.g. static or dynamic forces
Landscapes
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- General Physics & Mathematics (AREA)
- Theoretical Computer Science (AREA)
- Evolutionary Computation (AREA)
- General Engineering & Computer Science (AREA)
- Geometry (AREA)
- Computer Hardware Design (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geophysics (AREA)
- Braking Systems And Boosters (AREA)
- Investigating Strength Of Materials By Application Of Mechanical Stress (AREA)
- Mounting, Exchange, And Manufacturing Of Dies (AREA)
Abstract
A computer implemented method for simulating hydraulic fracturing in a naturally fractured reservoir is described. In an embodiment, the method comprises: initiating an extended finite element method (XFEM) model for simulating the hydraulic fracturing; creating a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property; defining a perforation location in the mesh for initiating hydraulic fracturing; and simulating the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
Description
METHOD AND SYSTEM FOR SIMULATING HYDRAULIC FRACTURING IN A
NATURALLY FRACTURED RESERVOIR
Technical Field The present disclosure relates to a method and system for simulating hydraulic fracturing in a naturally fractured reservoir, particularly, for simulating hydraulic fracturing using an extended finite element method (XFEM).
Background Hydraulic fracturing in a naturally fractured reservoir is complicated and challenging due to different types of interactions between a hydraulic fracture (HF) and a natural fracture.
Examples of such interactions are shown in Figure 1. As shown at 102 of Figure 1, a HF
may encounter a NF as it propagates in a naturally fractured reservoir. The HF
may either be arrested by the NF as shown at 104 or may cross the NF as shown at 106. In an event that the HF is arrested by the NF. The HF propagates along the NF
which leads to NF dilation as shown at 108 of Figure 1. In an event that the HF crosses the NF, the NF can either stay closed as shown at 110 of Figure 1 or the HF can cause fissure opening of the NF as shown in at 112 of Figure 1. An appropriate model for simulating hydraulic fracturing in a naturally fractured reservoir which takes into account interactions between the HF and the NF is therefore required for optimizing hydraulic fracture design.
A number of numerical methods have been developed to simulate the interactions between HFs and NFs. For example, the Displacement Discontinuity Method (DDM) and the Discrete Element Method (DEM) have been used. These methods, however, have limitations in simulating full 3D poro-elastic behaviors of reservoirs, for example, in simulating pore pressure alteration due to fluid injection and hydraulic fracture propagation. To answer this challenge, the eXtended Finite Element Method (XFEM) has been developed which is capable of simulating an interaction between a HF and a NF
with full 3D poro-elastic analysis capacity. The XFEM is a numerical technique which has extended conventional finite element methods by using partition of unity to allow presence of discontinuities in an element by enriching degrees of freedom with special displacement functions. XFEM has been used to model initiation and propagation of various discontinuities, such as cracks and material interfaces, without the need to pre-define crack paths which is a requirement in other methods such as the DEM.
NATURALLY FRACTURED RESERVOIR
Technical Field The present disclosure relates to a method and system for simulating hydraulic fracturing in a naturally fractured reservoir, particularly, for simulating hydraulic fracturing using an extended finite element method (XFEM).
Background Hydraulic fracturing in a naturally fractured reservoir is complicated and challenging due to different types of interactions between a hydraulic fracture (HF) and a natural fracture.
Examples of such interactions are shown in Figure 1. As shown at 102 of Figure 1, a HF
may encounter a NF as it propagates in a naturally fractured reservoir. The HF
may either be arrested by the NF as shown at 104 or may cross the NF as shown at 106. In an event that the HF is arrested by the NF. The HF propagates along the NF
which leads to NF dilation as shown at 108 of Figure 1. In an event that the HF crosses the NF, the NF can either stay closed as shown at 110 of Figure 1 or the HF can cause fissure opening of the NF as shown in at 112 of Figure 1. An appropriate model for simulating hydraulic fracturing in a naturally fractured reservoir which takes into account interactions between the HF and the NF is therefore required for optimizing hydraulic fracture design.
A number of numerical methods have been developed to simulate the interactions between HFs and NFs. For example, the Displacement Discontinuity Method (DDM) and the Discrete Element Method (DEM) have been used. These methods, however, have limitations in simulating full 3D poro-elastic behaviors of reservoirs, for example, in simulating pore pressure alteration due to fluid injection and hydraulic fracture propagation. To answer this challenge, the eXtended Finite Element Method (XFEM) has been developed which is capable of simulating an interaction between a HF and a NF
with full 3D poro-elastic analysis capacity. The XFEM is a numerical technique which has extended conventional finite element methods by using partition of unity to allow presence of discontinuities in an element by enriching degrees of freedom with special displacement functions. XFEM has been used to model initiation and propagation of various discontinuities, such as cracks and material interfaces, without the need to pre-define crack paths which is a requirement in other methods such as the DEM.
2 Despite the aforementioned advantages, XFEM has its limitations. For example, the XFEM only allows one fracture to exist within a particular element. The fracture is not allowed to turn more than 90 degrees within the particular element, and it may not branch.
Particularly since XFEM only allows one fracture to exist within the particular element, it is not considered a suitable candidate for simulating interactions (especially the crossing interactions 106, 110, 112) between multiple fractures.
It is therefore desirable to provide a method and system for simulating hydraulic fracturing in a naturally fractured reservoir which address the aforementioned problems and/or provides a useful alternative. Further, other desirable features and characteristics will become apparent from the subsequent detailed description and the appended claims, taken in conjunction with the accompanying drawings and this background of the disclosure.
Summary Aspects of the present application relate to a method and system for simulating hydraulic fracturing in a naturally fractured reservoir.
In accordance with a first aspect, there is provided a computer implemented method for simulating hydraulic fracturing in a naturally fractured reservoir, the method comprising:
(i) initiating an extended finite element method (XFEM) model for simulating the hydraulic fracturing; (ii) creating a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property; (iii) defining a perforation location in the mesh for initiating hydraulic fracturing;
and (iv) simulating the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
By creating the mesh which comprises first and second types of reservoir region having a first and second material property respectively, natural factures in the naturally fractured reservoir can be simulated by using the defined second type of reservoir region in the mesh. This second type of reservoir region can be used to emulate natural fractures with weak cohesion and high fluid permeability, thereby allowing interactions between hydraulic fractures and natural fractures to be simulated using this continuum natural fracture approach. This advantageously circumvents the limitation of existing
Particularly since XFEM only allows one fracture to exist within the particular element, it is not considered a suitable candidate for simulating interactions (especially the crossing interactions 106, 110, 112) between multiple fractures.
It is therefore desirable to provide a method and system for simulating hydraulic fracturing in a naturally fractured reservoir which address the aforementioned problems and/or provides a useful alternative. Further, other desirable features and characteristics will become apparent from the subsequent detailed description and the appended claims, taken in conjunction with the accompanying drawings and this background of the disclosure.
Summary Aspects of the present application relate to a method and system for simulating hydraulic fracturing in a naturally fractured reservoir.
In accordance with a first aspect, there is provided a computer implemented method for simulating hydraulic fracturing in a naturally fractured reservoir, the method comprising:
(i) initiating an extended finite element method (XFEM) model for simulating the hydraulic fracturing; (ii) creating a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property; (iii) defining a perforation location in the mesh for initiating hydraulic fracturing;
and (iv) simulating the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
By creating the mesh which comprises first and second types of reservoir region having a first and second material property respectively, natural factures in the naturally fractured reservoir can be simulated by using the defined second type of reservoir region in the mesh. This second type of reservoir region can be used to emulate natural fractures with weak cohesion and high fluid permeability, thereby allowing interactions between hydraulic fractures and natural fractures to be simulated using this continuum natural fracture approach. This advantageously circumvents the limitation of existing
3 XFEM simulation which limits only one fracture within a particular element as discussed above, thereby providing a holistic and accurate approach in simulating hydraulic fracturing in a naturally fractured reservoir using the XFEM model.
Further, the present method has a couple of distinctive advantages compared to traditional fracture interaction techniques such as the displacement discontinuity method (DDM) and the discrete element method (DEM). For example, the present method which utilizes the XFEM model is capable of full three-dimensional (3D) poro-elastic and poro-elasto-plastic analyses which lead to more accurate calculations for pore pressures and/or leak-off coefficients along the natural fractures. In addition, the present method does not require a predefined fracture path for directing a natural fracture crossing of a hydraulic fracture unlike that for the DEM. This therefore provides a more accurate approach in simulating hydraulic fracturing in a naturally fractured reservoir.
The method may comprise: defining at least one parameter of the second type of reservoir region, the at least one parameter of the second type of reservoir region includes a length of the natural fracture, a width of the natural fracture, a thickness of the natural fracture, a dip of the natural fracture, or a strike of the natural fracture.
The method may comprise: defining at least one parameter of the first material property, the at least one parameter of the first material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The method may comprise: defining at least one parameter of the second material property, the at least one parameter of the second material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The method may comprise: defining a plurality of parameters associated with an injection fluid for the hydraulic fracturing, the plurality of parameters include an injection rate of the fluid, a volume of the fluid, an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid.
The method may comprise: optimizing the plurality of parameters associated with the injection fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing.
The method may comprise: calculating an amount of fault slip generated as a result of the hydraulic fracturing; and estimating a magnitude of an induced seismic event using
Further, the present method has a couple of distinctive advantages compared to traditional fracture interaction techniques such as the displacement discontinuity method (DDM) and the discrete element method (DEM). For example, the present method which utilizes the XFEM model is capable of full three-dimensional (3D) poro-elastic and poro-elasto-plastic analyses which lead to more accurate calculations for pore pressures and/or leak-off coefficients along the natural fractures. In addition, the present method does not require a predefined fracture path for directing a natural fracture crossing of a hydraulic fracture unlike that for the DEM. This therefore provides a more accurate approach in simulating hydraulic fracturing in a naturally fractured reservoir.
The method may comprise: defining at least one parameter of the second type of reservoir region, the at least one parameter of the second type of reservoir region includes a length of the natural fracture, a width of the natural fracture, a thickness of the natural fracture, a dip of the natural fracture, or a strike of the natural fracture.
The method may comprise: defining at least one parameter of the first material property, the at least one parameter of the first material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The method may comprise: defining at least one parameter of the second material property, the at least one parameter of the second material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The method may comprise: defining a plurality of parameters associated with an injection fluid for the hydraulic fracturing, the plurality of parameters include an injection rate of the fluid, a volume of the fluid, an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid.
The method may comprise: optimizing the plurality of parameters associated with the injection fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing.
The method may comprise: calculating an amount of fault slip generated as a result of the hydraulic fracturing; and estimating a magnitude of an induced seismic event using
4 the calculated amount of fault slip. By calculating the amount of fault slip generated as a result of the hydraulic fracturing, a quantitative estimate of the magnitude of the induced seismic event can be obtained. This is more accurate than existing qualitative estimate of the magnitude of the induced seismic event.
Where estimating the magnitude of the induced seismic event may comprise performing a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
In accordance with a second aspect, there is provided a computer readable medium storing processor executable instructions which when executed on a processor cause the processor to carry out any of the preceding method.
In accordance with a third aspect, there is provided a system for simulating hydraulic fracturing in a naturally fractured reservoir, the system comprising a processor and a data storing computer program instructions operable to cause the processor to:
initiate an extended finite element method (XFEM) model for simulating the hydraulic fracturing;
create a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property;
define a perforation location in the mesh for initiating hydraulic fracturing; and simulate the hydraulic fracturing in the naturally fractured reservoir using the XFEM
model.
The data storage may store computer program instructions operable to cause the processor to: define at least one parameter of the second type of reservoir region, the at least one parameter of the second type of reservoir region includes a length of the natural fracture, a width of the natural fracture, a thickness of the natural fracture, a dip of the natural fracture, or a strike of the natural fracture.
The data storage may store computer program instructions operable to cause the processor to: define at least one parameter of the first material property, the at least one parameter of the first material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The data storage may store computer program instructions operable to cause the processor to: define at least one parameter of the second material property, the at least one parameter of the second material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The data storage may store computer program instructions operable to cause the processor to: define a plurality of parameters associated with a fluid for the hydraulic
Where estimating the magnitude of the induced seismic event may comprise performing a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
In accordance with a second aspect, there is provided a computer readable medium storing processor executable instructions which when executed on a processor cause the processor to carry out any of the preceding method.
In accordance with a third aspect, there is provided a system for simulating hydraulic fracturing in a naturally fractured reservoir, the system comprising a processor and a data storing computer program instructions operable to cause the processor to:
initiate an extended finite element method (XFEM) model for simulating the hydraulic fracturing;
create a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property;
define a perforation location in the mesh for initiating hydraulic fracturing; and simulate the hydraulic fracturing in the naturally fractured reservoir using the XFEM
model.
The data storage may store computer program instructions operable to cause the processor to: define at least one parameter of the second type of reservoir region, the at least one parameter of the second type of reservoir region includes a length of the natural fracture, a width of the natural fracture, a thickness of the natural fracture, a dip of the natural fracture, or a strike of the natural fracture.
The data storage may store computer program instructions operable to cause the processor to: define at least one parameter of the first material property, the at least one parameter of the first material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The data storage may store computer program instructions operable to cause the processor to: define at least one parameter of the second material property, the at least one parameter of the second material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
The data storage may store computer program instructions operable to cause the processor to: define a plurality of parameters associated with a fluid for the hydraulic
5 fracturing, the plurality of parameters include an injection rate of the fluid, a volume of the fluid, an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid.
The data storage may store computer program instructions operable to cause the processor to: optimize the plurality of parameters associated with the fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing.
The data storage may store computer program instructions operable to cause the processor to: calculate an amount of fault slip generated as a result of the hydraulic fracturing; and estimate a magnitude of an induced seismic event using the calculated amount of fault slip.
The data storage may store computer program instructions operable to cause the processor to: perform a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
The mesh may comprise a plurality of regions having the second type of material property as defined by the second type of reservoir region.
It should be appreciated that features relating to one aspect may be applicable to the other aspects. Embodiments therefore provide a method and system for simulating hydraulic fracturing in a naturally fractured reservoir. By creating the mesh which comprises first and second types of reservoir region having a first and second material property respectively, natural factures in the naturally fractured reservoir can be simulated by using the defined second type of reservoir region in the mesh.
This second type of reservoir region can be used to emulate natural fractures with weak cohesion and high fluid permeability, thereby allowing interactions between hydraulic fractures and natural fractures to be simulated using this continuum natural fracture approach. This advantageously circumvents the limitation of existing XFEM simulation which limits only one fracture within a particular element, while retaining the existing advantages of the XFEM model. This provides a holistic and accurate approach in simulating hydraulic fracturing in a naturally fractured reservoir using the XFEM model.
The data storage may store computer program instructions operable to cause the processor to: optimize the plurality of parameters associated with the fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing.
The data storage may store computer program instructions operable to cause the processor to: calculate an amount of fault slip generated as a result of the hydraulic fracturing; and estimate a magnitude of an induced seismic event using the calculated amount of fault slip.
The data storage may store computer program instructions operable to cause the processor to: perform a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
The mesh may comprise a plurality of regions having the second type of material property as defined by the second type of reservoir region.
It should be appreciated that features relating to one aspect may be applicable to the other aspects. Embodiments therefore provide a method and system for simulating hydraulic fracturing in a naturally fractured reservoir. By creating the mesh which comprises first and second types of reservoir region having a first and second material property respectively, natural factures in the naturally fractured reservoir can be simulated by using the defined second type of reservoir region in the mesh.
This second type of reservoir region can be used to emulate natural fractures with weak cohesion and high fluid permeability, thereby allowing interactions between hydraulic fractures and natural fractures to be simulated using this continuum natural fracture approach. This advantageously circumvents the limitation of existing XFEM simulation which limits only one fracture within a particular element, while retaining the existing advantages of the XFEM model. This provides a holistic and accurate approach in simulating hydraulic fracturing in a naturally fractured reservoir using the XFEM model.
6 Brief description of the drawinas Embodiments will now be described, by way of example only, with reference to the following drawings, in which:
Figure 1 shows a schematic diagram illustrating a hydraulic fracture interaction with a natural fracture, which shows the hydraulic fracture either being arrested by or crossing the natural fracture due to mechanical and hydraulic (leak-off) characteristics of the natural fracture and a hydraulic fracturing design;
Figure 2 shows a block diagram of a hydraulic fracture simulation system in accordance with an embodiment;
Figure 3 is a flowchart showing steps of a method for simulating hydraulic fracturing in a naturally fractured reservoir in accordance with an embodiment;
Figure 4 is a flowchart showing steps of a method for estimating a magnitude of an induced seismic event using a calculated amount of fault slip in accordance with an embodiment;
Figures 5A, 5B and 5C show diagrams of a mesh used in simulating hydraulic fracturing using the method of Figure 3 in accordance with an embodiment, where Figure 5A
shows a schematic of the mesh comprising a first type of reservoir region representing a rock matrix and a second type of reservoir region representing a natural fracture, Figure 5B
shows a schematic of the mesh with an introduction of the perforation locations for initiating hydraulic fracturing, and Figure 5C shows a schematic of the mesh with the simulated hydraulic fracturing;
Figures 6A and 6B show diagrams of the mesh used in the XFEM simulation method of Figure 3 in accordance with an embodiment, where Figure 6A shows a schematic diagram of a model for the mesh and Figure 6B shows the mesh used on the XFEM
simulation interface;
Figures 7A and 7B show diagrams of a natural fracture which can be defined in the mesh of Figures 6A and 6B in accordance with an embodiment, where Figure 7A shows a diagram of the natural fracture in a top-down view of the mesh and Figure 7B
shows a diagram of the natural fracture in a front end view of the mesh;
Figure 1 shows a schematic diagram illustrating a hydraulic fracture interaction with a natural fracture, which shows the hydraulic fracture either being arrested by or crossing the natural fracture due to mechanical and hydraulic (leak-off) characteristics of the natural fracture and a hydraulic fracturing design;
Figure 2 shows a block diagram of a hydraulic fracture simulation system in accordance with an embodiment;
Figure 3 is a flowchart showing steps of a method for simulating hydraulic fracturing in a naturally fractured reservoir in accordance with an embodiment;
Figure 4 is a flowchart showing steps of a method for estimating a magnitude of an induced seismic event using a calculated amount of fault slip in accordance with an embodiment;
Figures 5A, 5B and 5C show diagrams of a mesh used in simulating hydraulic fracturing using the method of Figure 3 in accordance with an embodiment, where Figure 5A
shows a schematic of the mesh comprising a first type of reservoir region representing a rock matrix and a second type of reservoir region representing a natural fracture, Figure 5B
shows a schematic of the mesh with an introduction of the perforation locations for initiating hydraulic fracturing, and Figure 5C shows a schematic of the mesh with the simulated hydraulic fracturing;
Figures 6A and 6B show diagrams of the mesh used in the XFEM simulation method of Figure 3 in accordance with an embodiment, where Figure 6A shows a schematic diagram of a model for the mesh and Figure 6B shows the mesh used on the XFEM
simulation interface;
Figures 7A and 7B show diagrams of a natural fracture which can be defined in the mesh of Figures 6A and 6B in accordance with an embodiment, where Figure 7A shows a diagram of the natural fracture in a top-down view of the mesh and Figure 7B
shows a diagram of the natural fracture in a front end view of the mesh;
7 Figure 8 shows a diagram of perforations for initiating hydraulic fracturing in a natural fractured reservoir in accordance with an embodiment;
Figure 9 shows a diagram of a two-stage fluid injection treatment at the perforations of Figure 8 for performing the hydraulic fracturing in the natural fractured reservoir in accordance with an embodiment;
Figure 10 shows a diagram of a simulation output of an arresting of a hydraulic fracture by a natural fracture in accordance with an embodiment;
Figures 11A, 11B and 11C show diagrams of a simulation output of a hydraulic fracture crossing a natural fracture in accordance with an embodiment, where Figure 11A
shows a perspective view of a displacement contour plot of the simulation, Figure 11B shows a perspective view of an opening contour plot of the simulation and Figure 11C
shows a top view of the displacement contour plot of Figure 11A;
Figures 12A and 12B show plots for assessing risk of fault reactivation and induced seismicity, where Figure 12A shows a conventional critically stressed fault analysis plot and Figure 12B shows a conventional strain energy-based induced seismicity analysis plot;
Figures 13A and 13B show diagrams of a simulation output of a hydraulic fracture crossing a natural fracture in accordance with an embodiment, where Figure 13A
shows a perspective view of an opening contour plot of the simulation and Figure 13B
shows a top view of a displacement contour plot; and Figure 14 shows an illustration for estimating a magnitude of an induced seismic event by using a calculated amount of fault slip in accordance with an embodiment.
Detailed description Exemplary embodiments relate to a method and system for simulating hydraulic fracturing in a naturally fractured reservoir, particularly, for simulating hydraulic fracturing using an extended finite element method (XFEM).
XFEM has been implemented in multiple commercial FEM software including Abaqus.
Abaqus version 6.9 (2009) introduces the ability to model cracks in the FEM
framework by using a version of the enriched element formulation to incorporate XFEM
into the traditional FEM framework. The Abaqus software has the capacity to simulate full 3D
Figure 9 shows a diagram of a two-stage fluid injection treatment at the perforations of Figure 8 for performing the hydraulic fracturing in the natural fractured reservoir in accordance with an embodiment;
Figure 10 shows a diagram of a simulation output of an arresting of a hydraulic fracture by a natural fracture in accordance with an embodiment;
Figures 11A, 11B and 11C show diagrams of a simulation output of a hydraulic fracture crossing a natural fracture in accordance with an embodiment, where Figure 11A
shows a perspective view of a displacement contour plot of the simulation, Figure 11B shows a perspective view of an opening contour plot of the simulation and Figure 11C
shows a top view of the displacement contour plot of Figure 11A;
Figures 12A and 12B show plots for assessing risk of fault reactivation and induced seismicity, where Figure 12A shows a conventional critically stressed fault analysis plot and Figure 12B shows a conventional strain energy-based induced seismicity analysis plot;
Figures 13A and 13B show diagrams of a simulation output of a hydraulic fracture crossing a natural fracture in accordance with an embodiment, where Figure 13A
shows a perspective view of an opening contour plot of the simulation and Figure 13B
shows a top view of a displacement contour plot; and Figure 14 shows an illustration for estimating a magnitude of an induced seismic event by using a calculated amount of fault slip in accordance with an embodiment.
Detailed description Exemplary embodiments relate to a method and system for simulating hydraulic fracturing in a naturally fractured reservoir, particularly, for simulating hydraulic fracturing using an extended finite element method (XFEM).
XFEM has been implemented in multiple commercial FEM software including Abaqus.
Abaqus version 6.9 (2009) introduces the ability to model cracks in the FEM
framework by using a version of the enriched element formulation to incorporate XFEM
into the traditional FEM framework. The Abaqus software has the capacity to simulate full 3D
8 poro-elastic behaviors of reservoirs (i.e. pore pressure alteration due to fluid injection and hydraulic fracture propagation) as well as tangential and normal fluid flow in XFEM
cracks. The present invention builds on XFEM modeling. Physical and mathematical models used in XFEM modeling (e.g. in the Abaqus simulation program) are not described here for clarity and succinctness.
Figure 2 shows a block diagram of a hydraulic fracturing simulation system 200 in accordance with an embodiment.
As shown in Figure 2, the hydraulic fracturing simulation system 200 is a computer system with memory that stores computer program modules which implement computer-implemented method for simulating hydraulic fracturing in a naturally fractured reservoir.
The hydraulic fracturing simulation system 200 comprises a processor 202, a working memory 204, an input module 206, an output module 208, a user interface 210, program storage 212 and data storage 214. The processor 202 may be implemented as one or more central processing unit (CPU) chips. The program storage 212 is a non-volatile storage device such as a hard disk drive which stores computer program modules such as a XFEM module 216 and a seismicity analysis module 218. The computer program modules are loaded into the working memory 204 for execution by the processor 202.
The input module 206 is an interface which allows data, for example data in relation to formation of the mesh, material properties of different regions of the mesh etc., to be received by the hydraulic fracturing simulation system 200. The output module 208 is an output device which allows data and results of analysis of calculated model parameters by the hydraulic fracturing simulation system 200 to be output. The output module 208 may be coupled to a display device or a printer. The user interface 210 allows a user of the hydraulic fracturing simulation system 200 to input selections and commands and may be implemented as a graphical user interface.
The program storage 212 stores the XFEM module 216 and the seismicity analysis module 218. The XFEM module 216 and the seismicity analysis module 218 cause the processor 202 to execute various hydraulic simulation and analysis processes which are described in more detail below. The program storage 212 may be referred to in some contexts as computer readable storage media and/or non-transitory computer readable media. As depicted in Figure 2, the computer program modules 216, 218 are distinct modules which perform respective functions implemented by the hydraulic fracturing simulation system 200. It will be appreciated that the boundaries between these modules
cracks. The present invention builds on XFEM modeling. Physical and mathematical models used in XFEM modeling (e.g. in the Abaqus simulation program) are not described here for clarity and succinctness.
Figure 2 shows a block diagram of a hydraulic fracturing simulation system 200 in accordance with an embodiment.
As shown in Figure 2, the hydraulic fracturing simulation system 200 is a computer system with memory that stores computer program modules which implement computer-implemented method for simulating hydraulic fracturing in a naturally fractured reservoir.
The hydraulic fracturing simulation system 200 comprises a processor 202, a working memory 204, an input module 206, an output module 208, a user interface 210, program storage 212 and data storage 214. The processor 202 may be implemented as one or more central processing unit (CPU) chips. The program storage 212 is a non-volatile storage device such as a hard disk drive which stores computer program modules such as a XFEM module 216 and a seismicity analysis module 218. The computer program modules are loaded into the working memory 204 for execution by the processor 202.
The input module 206 is an interface which allows data, for example data in relation to formation of the mesh, material properties of different regions of the mesh etc., to be received by the hydraulic fracturing simulation system 200. The output module 208 is an output device which allows data and results of analysis of calculated model parameters by the hydraulic fracturing simulation system 200 to be output. The output module 208 may be coupled to a display device or a printer. The user interface 210 allows a user of the hydraulic fracturing simulation system 200 to input selections and commands and may be implemented as a graphical user interface.
The program storage 212 stores the XFEM module 216 and the seismicity analysis module 218. The XFEM module 216 and the seismicity analysis module 218 cause the processor 202 to execute various hydraulic simulation and analysis processes which are described in more detail below. The program storage 212 may be referred to in some contexts as computer readable storage media and/or non-transitory computer readable media. As depicted in Figure 2, the computer program modules 216, 218 are distinct modules which perform respective functions implemented by the hydraulic fracturing simulation system 200. It will be appreciated that the boundaries between these modules
9 are exemplary only, and that alternative embodiments may merge modules or impose an alternative decomposition of functionality of modules. For example, the modules discussed herein may be decomposed into sub-modules to be executed as multiple computer processes, and, optionally, on multiple computers. Moreover, alternative embodiments may combine multiple instances of a particular module or sub-module. It will also be appreciated that, while a software implementation of the computer program modules is described herein, these may alternatively be implemented as one or more hardware modules (such as field-programmable gate array(s) or application-specific integrated circuit(s)) comprising circuitry which implements equivalent functionality to that implemented in software.
The data storage 214 stores various model data and model parameters. As shown in Figure 2, the data storage 214 has storage for a XFEM model 220 and a seismicity model 222 for use with their corresponding modules 216, 218. In the present embodiment, the XFEM model 220 comprises a three-dimensional (3D) mesh model 224, a fluid injection model 226, physical models 228 and model parameters 230. Data entered by the user in relation to creating a 3D mesh for simulating hydraulic fracturing is stored in the 3D
mesh model 224. Similarly, data entered in relation to a fluid injection model for simulating hydraulic fracturing is stored in the fluid injection model 226.
The physical models 228 and the model parameters 230 store data in relation to physical models (e.g.
existing physical and mathematical models used by XFEM for simulation hydraulic fracturing) and model parameters (e.g. various parameters used in relation to material properties etc.) respectively. The seismicity analysis model 222 stores data in relation to estimating a magnitude of an induced seismic event caused by hydraulic fracturing in a naturally fractured reservoir, for example, data in relation to strain energy-based induced seismicity analysis etc.
Figure 3 shows a flowchart showing steps of a method 300 for simulating hydraulic fracturing in a naturally fractured reservoir in accordance with an embodiment. The method 300 is carried out on the hydraulic fracturing simulation system 200.
In a step 302, the XFEM module 216 is executed by the processor 202 to initiate an extended finite element method (XFEM) model for simulating the hydraulic fracturing.
In a step 304, the XFEM module 216 is executed by the processor 202 to create a mesh for the naturally fractured reservoir, using data and/or parameters from the 3D mesh model 224 and the model parameters 230. The mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property. The first material property being different from the second material property.
Detail of creating a mesh for the naturally fractured reservoir is discussed below in relation to Figures 5A, 5 6A and 6B.
In a step 306, the XFEM module 216 is executed by the processor 202 to define a perforation location in the mesh for initiating hydraulic fracturing. This is discussed in detail in relation to Figure 5B below.
In a step 308, the XFEM module 216 is executed by the processor 202 to define a
The data storage 214 stores various model data and model parameters. As shown in Figure 2, the data storage 214 has storage for a XFEM model 220 and a seismicity model 222 for use with their corresponding modules 216, 218. In the present embodiment, the XFEM model 220 comprises a three-dimensional (3D) mesh model 224, a fluid injection model 226, physical models 228 and model parameters 230. Data entered by the user in relation to creating a 3D mesh for simulating hydraulic fracturing is stored in the 3D
mesh model 224. Similarly, data entered in relation to a fluid injection model for simulating hydraulic fracturing is stored in the fluid injection model 226.
The physical models 228 and the model parameters 230 store data in relation to physical models (e.g.
existing physical and mathematical models used by XFEM for simulation hydraulic fracturing) and model parameters (e.g. various parameters used in relation to material properties etc.) respectively. The seismicity analysis model 222 stores data in relation to estimating a magnitude of an induced seismic event caused by hydraulic fracturing in a naturally fractured reservoir, for example, data in relation to strain energy-based induced seismicity analysis etc.
Figure 3 shows a flowchart showing steps of a method 300 for simulating hydraulic fracturing in a naturally fractured reservoir in accordance with an embodiment. The method 300 is carried out on the hydraulic fracturing simulation system 200.
In a step 302, the XFEM module 216 is executed by the processor 202 to initiate an extended finite element method (XFEM) model for simulating the hydraulic fracturing.
In a step 304, the XFEM module 216 is executed by the processor 202 to create a mesh for the naturally fractured reservoir, using data and/or parameters from the 3D mesh model 224 and the model parameters 230. The mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property. The first material property being different from the second material property.
Detail of creating a mesh for the naturally fractured reservoir is discussed below in relation to Figures 5A, 5 6A and 6B.
In a step 306, the XFEM module 216 is executed by the processor 202 to define a perforation location in the mesh for initiating hydraulic fracturing. This is discussed in detail in relation to Figure 5B below.
In a step 308, the XFEM module 216 is executed by the processor 202 to define a
10 plurality of parameters associated with an injection fluid for the hydraulic fracturing, the plurality of parameters include an injection rate of the fluid, a volume of the fluid, an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid. The plurality of parameters defined are stored in the fluid injection model 226 for use in the simulation of the hydraulic fracturing by the XFEM
module 216.
In a step 310, the XFEM module 216 is executed by the processor 202 to simulate the hydraulic fracturing in the naturally fractured reservoir using the XFEM model 220. The simulation of the hydraulic fracturing takes into account the created mesh using data stored in the 3D mesh model 224, the data stored in relation to the fluid injection model 226, and the physical models 228 and the model parameters 230. This is discussed in more detail in relation to Figure 5C.
In a step 312, the XFEM module 216 is executed by the processor 202 to optimize the plurality of parameters associated with the injection fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing. In an embodiment, the XFEM module 216 is configured to optimize the plurality of parameters of the fluid injection model 226 in tandem with the simulated results (e.g. the simulated reservoir volume and the fracture conductivity) generated by the XFEM module to achieve a maximum stimulated reservoir volume and/or a maximum fracture conductivity given the created mesh and the perforation location.
Figure 4 shows a flowchart showing steps of a method 400 for estimating a magnitude of an induced seismic event using the calculated amount of fault slip in accordance with an embodiment. The method 400 is carried out on the hydraulic fracturing simulation system 200.
module 216.
In a step 310, the XFEM module 216 is executed by the processor 202 to simulate the hydraulic fracturing in the naturally fractured reservoir using the XFEM model 220. The simulation of the hydraulic fracturing takes into account the created mesh using data stored in the 3D mesh model 224, the data stored in relation to the fluid injection model 226, and the physical models 228 and the model parameters 230. This is discussed in more detail in relation to Figure 5C.
In a step 312, the XFEM module 216 is executed by the processor 202 to optimize the plurality of parameters associated with the injection fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing. In an embodiment, the XFEM module 216 is configured to optimize the plurality of parameters of the fluid injection model 226 in tandem with the simulated results (e.g. the simulated reservoir volume and the fracture conductivity) generated by the XFEM module to achieve a maximum stimulated reservoir volume and/or a maximum fracture conductivity given the created mesh and the perforation location.
Figure 4 shows a flowchart showing steps of a method 400 for estimating a magnitude of an induced seismic event using the calculated amount of fault slip in accordance with an embodiment. The method 400 is carried out on the hydraulic fracturing simulation system 200.
11 In a step 402, the XFEM module 216 is executed by the processor 202 to calculate an amount of fault slip generated as a result of the hydraulic fracturing. In an embodiment, the amount of fault slip generated as a result of the hydraulic fracturing can be calculated or read off using the simulated results from the hydraulic fracturing in the naturally fractured reservoir, for example, in the step 310 as described above.
In a step 404, the seismicity analysis module 218 is executed by the processor 202 to estimate a magnitude of an induced seismic event using the calculated amount of fault slip. In an embodiment, to estimate the magnitude of the induced seismic event, the seismicity analysis module 218 is executed by the processor 202 to perform a strain energy-based induced seismicity analysis using the calculated amount of fault slip obtained in the step 402. Detail of this is further described in relation to Figure 14. Data in relation to the energy-based induced seismicity analysis is stored in the seismicity analysis model 222.
An exemplary embodiment for simulating hydraulic fracturing in a naturally fractured reservoir is described below, in conjunction with Figures 5A to Figure 11C.
Figures 5A, 5B and 5C show diagrams of a mesh used in simulating hydraulic fracturing using the method of Figure 3 in accordance with an embodiment.
Figure 5A shows a schematic of the mesh 500 comprising a first type of reservoir region 502 representing a rock matrix and a second type of reservoir region 504 representing a natural fracture, in accordance with an embodiment. Once the XFEM model is initiated by the XFEM module 216, creation of the XFEM modelling begins with the creation of the mesh 500. The mesh 500 represents the geometry of the rock matrix and the natural fracture in the naturally fractured reservoir. As shown in Figure 5A, the mesh is initially drawn in two dimensions and can be later extruded to form the 3D mesh.
Examples of the 3D mesh are shown in Figures 6A and 6B. Figure 6A shows a schematic diagram of a model 600 for the 3D mesh and Figure 6B shows the mesh 610 as displayed on a XFEM simulation interface. As shown in Figures 6A and 6B, the model 600 and the mesh 610 each comprises three layers, Layer 0 (602), Layer 1 (604) and Layer 2 (606). The three layers can be used to represent different material layers making up the naturally fractured reservoir. The width and length of the model 600 or mesh 610 can also be defined at this stage.
In a step 404, the seismicity analysis module 218 is executed by the processor 202 to estimate a magnitude of an induced seismic event using the calculated amount of fault slip. In an embodiment, to estimate the magnitude of the induced seismic event, the seismicity analysis module 218 is executed by the processor 202 to perform a strain energy-based induced seismicity analysis using the calculated amount of fault slip obtained in the step 402. Detail of this is further described in relation to Figure 14. Data in relation to the energy-based induced seismicity analysis is stored in the seismicity analysis model 222.
An exemplary embodiment for simulating hydraulic fracturing in a naturally fractured reservoir is described below, in conjunction with Figures 5A to Figure 11C.
Figures 5A, 5B and 5C show diagrams of a mesh used in simulating hydraulic fracturing using the method of Figure 3 in accordance with an embodiment.
Figure 5A shows a schematic of the mesh 500 comprising a first type of reservoir region 502 representing a rock matrix and a second type of reservoir region 504 representing a natural fracture, in accordance with an embodiment. Once the XFEM model is initiated by the XFEM module 216, creation of the XFEM modelling begins with the creation of the mesh 500. The mesh 500 represents the geometry of the rock matrix and the natural fracture in the naturally fractured reservoir. As shown in Figure 5A, the mesh is initially drawn in two dimensions and can be later extruded to form the 3D mesh.
Examples of the 3D mesh are shown in Figures 6A and 6B. Figure 6A shows a schematic diagram of a model 600 for the 3D mesh and Figure 6B shows the mesh 610 as displayed on a XFEM simulation interface. As shown in Figures 6A and 6B, the model 600 and the mesh 610 each comprises three layers, Layer 0 (602), Layer 1 (604) and Layer 2 (606). The three layers can be used to represent different material layers making up the naturally fractured reservoir. The width and length of the model 600 or mesh 610 can also be defined at this stage.
12 The physical properties of the rock matrix and the natural fracture can then be introduced.
For example, parameters of a material property of the rock matrix and the parameters of a material property of the natural fracture can be defined. The parameters of the material property of the rock matrix and/or the natural fracture includes: a Young's modulus, a density, a Poisson's ratio, a cohesive fracture energy, a porosity, a permeability, a leak-off coefficient and/or a damage criterion. Each of the regions of the mesh 500 can be defined to have different material properties and can be named accordingly.
For example, as shown in Figure 5A, the first type of reservoir region 502 representing the rock matrix can be assigned a first material property and the second type of reservoir region 504 representing the natural fracture can be assigned a second material property, where the first material property is different from the second material property.
An example for defining the parameters of the two different types of regions is presented below:
*************************************************
for rock matrix (i.e. first type of reservoir region 502) *************************************************
"Material, name=Rock_Mass *Damage Initiation, criterion=MAXPS, tolerance=0.01, growth tolerance=0.01 *** Pa 1.0e+6, "Damage Evolution, type=ENERGY, mixed mode behavior=BK, power=2.0 *** J/m2, J/m2, J/m2 25, 25, 25 *Elastic *** Pa, unitless 4.0e+10, 0.25 "Fluid Leakoff *** m3/Pa.s le-12, le-12 *Gap Flow *** Pa.s 5e-04, *Permeability, specific=9.8e+02 m/s, unitless le-08, 0.05 for natural fractures (i.e. second type of reservoir region 504) *************************************************
*Material, name=Natural_Fracture *Damage Initiation, criterion=MAXPS, tolerance=0.01, growth tolerance=0.01 *** Pa 1.0e+4, "Damage Evolution, type=ENERGY, mixed mode behavior=BK, power=2.0 *** J/m2, J/m2, J/m2 2.5, 2.5, 2.5 *Elastic
For example, parameters of a material property of the rock matrix and the parameters of a material property of the natural fracture can be defined. The parameters of the material property of the rock matrix and/or the natural fracture includes: a Young's modulus, a density, a Poisson's ratio, a cohesive fracture energy, a porosity, a permeability, a leak-off coefficient and/or a damage criterion. Each of the regions of the mesh 500 can be defined to have different material properties and can be named accordingly.
For example, as shown in Figure 5A, the first type of reservoir region 502 representing the rock matrix can be assigned a first material property and the second type of reservoir region 504 representing the natural fracture can be assigned a second material property, where the first material property is different from the second material property.
An example for defining the parameters of the two different types of regions is presented below:
*************************************************
for rock matrix (i.e. first type of reservoir region 502) *************************************************
"Material, name=Rock_Mass *Damage Initiation, criterion=MAXPS, tolerance=0.01, growth tolerance=0.01 *** Pa 1.0e+6, "Damage Evolution, type=ENERGY, mixed mode behavior=BK, power=2.0 *** J/m2, J/m2, J/m2 25, 25, 25 *Elastic *** Pa, unitless 4.0e+10, 0.25 "Fluid Leakoff *** m3/Pa.s le-12, le-12 *Gap Flow *** Pa.s 5e-04, *Permeability, specific=9.8e+02 m/s, unitless le-08, 0.05 for natural fractures (i.e. second type of reservoir region 504) *************************************************
*Material, name=Natural_Fracture *Damage Initiation, criterion=MAXPS, tolerance=0.01, growth tolerance=0.01 *** Pa 1.0e+4, "Damage Evolution, type=ENERGY, mixed mode behavior=BK, power=2.0 *** J/m2, J/m2, J/m2 2.5, 2.5, 2.5 *Elastic
13 ***Pa, unitless 4.0e+08, 0.35 "Fluid Leakoff *** m3/Pa.s le-10, le-10 *Gap Flow Pa .s 5e-04, "Permeability, specific=9.8e+02 *** m/s, unitless le-06, 0.25 Further, parameters and physical properties of the natural fractures in the mesh 500 can be defined. Figures 7A and 7B show diagrams of a natural fracture which can be defined in the mesh 500 in accordance with an embodiment.
Figure 7A shows a diagram 700 of the natural fracture 702 in a top-down view 704 of the mesh 500. As shown in Figure 7A, physical properties such as a width 706 and a strike o 708 of the natural fracture can be defined. In the present embodiment, the width 706 is 300m and the strike e 708 is 30 degrees. Perforations 710 for initiating the hydraulic fracturing and a section 712 of the wells are also shown.
Figure 7B shows a diagram 720 of the natural fracture 702 in a front-end view 722 of the mesh. A dip 724 of the natural fracture 702 is also shown. In the present embodiment, the dip 724 is 90 degrees.
Although not explicitly shown in the Figures 7A and 7B, other parameters associated with the natural fracture 702 can also be defined. The other parameters may include a length of the natural fracture and a thickness of the natural fracture.
The model is then assembled. Within assembly, all the parts are combined to produce a single system where all its constituents will be simulated.
After the mesh 500 is well defined and assembled, perforation locations for initiating the hydraulic fracturing can be defined.
Figure 5B shows a schematic of the mesh 500 with an introduction of the perforation locations 506 for initiating hydraulic fracturing. The location and other characteristics of the perforations can be defined in the XFEM model. This is shown in Figure 8.
Figure 8 shows a diagram 800 of the perforation locations 802 along a horizontal section 804 of the wells in a target zone in accordance with an embodiment. In the present embodiment, a depth of the perforations is set to 0.1 m.
Figure 7A shows a diagram 700 of the natural fracture 702 in a top-down view 704 of the mesh 500. As shown in Figure 7A, physical properties such as a width 706 and a strike o 708 of the natural fracture can be defined. In the present embodiment, the width 706 is 300m and the strike e 708 is 30 degrees. Perforations 710 for initiating the hydraulic fracturing and a section 712 of the wells are also shown.
Figure 7B shows a diagram 720 of the natural fracture 702 in a front-end view 722 of the mesh. A dip 724 of the natural fracture 702 is also shown. In the present embodiment, the dip 724 is 90 degrees.
Although not explicitly shown in the Figures 7A and 7B, other parameters associated with the natural fracture 702 can also be defined. The other parameters may include a length of the natural fracture and a thickness of the natural fracture.
The model is then assembled. Within assembly, all the parts are combined to produce a single system where all its constituents will be simulated.
After the mesh 500 is well defined and assembled, perforation locations for initiating the hydraulic fracturing can be defined.
Figure 5B shows a schematic of the mesh 500 with an introduction of the perforation locations 506 for initiating hydraulic fracturing. The location and other characteristics of the perforations can be defined in the XFEM model. This is shown in Figure 8.
Figure 8 shows a diagram 800 of the perforation locations 802 along a horizontal section 804 of the wells in a target zone in accordance with an embodiment. In the present embodiment, a depth of the perforations is set to 0.1 m.
14 Following the definition of the perforations and their locations, a fluid injection treatment at the perforations can be defined. Figure 9 shows a diagram 900 of a two-stage fluid injection treatment at the perforations of Figure 8 for performing the hydraulic fracturing in the natural fractured reservoir in accordance with an embodiment. A plot 902 shows a rate of injection of the fluid (in L/min), while a plot 904 shows a volume of the fluid (in L) injected with time (in minutes). In the present embodiment, an injection rate of 3000 L/min is set for a first stage 906 and an injection rate of 9000 L/min is set for a second stage 908 of the fluid injection treatment. Although not explicitly shown in Figure 9, other parameters associated with the injection fluid for the hydraulic fracturing can also be defined. These other parameters include an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid. Further, a proppant used, a size of the proppant, a concentration of the proppant, a volume of the proppant, and a mass of the proppant for the fluid injection treatment can also be defined.
Following the definition of the fluid treatment step, interaction between the components of the system can be introduced. The fracture surface and propagation algorithm are defined, and the enrichment nodes within the simulation are also defined.
Although Figure 5 shows the mesh 500, the actual meshing of the model may be applied at this point. For simulation of the hydraulic fracturing using XFEM modelling, a hex type mesh can be implemented. Lastly, a job file is created. Simulation of the hydraulic fracturing is then performed by using the parameters and/or input data defined in the previous steps.
For the simulation of the hydraulic fracturing, the user may also define a step size and a step number to be simulated.
Figure 5C shows a schematic of the mesh 500 with the simulated hydraulic fracturing.
Three different interactions between the hydraulic fractures and the natural fractures are shown in Figure 5C. The line 508 shows a hydraulic fracture being arrested by the natural fracture. The line 510 shows a hydraulic fracture being diverted by the natural fracture.
The line 512 shows a hydraulic fracture crossing the natural fracture.
The simulation outputs of Figures 10 to 11C are generated using hydraulic fracturing with continuum natural fractures (i.e. thin weak conductive material) by using a representation of the mesh 500 (e.g. the mesh 600) in the XFEM model 220. The results of the continuum natural fracture approach as exemplified by the method 300 demonstrated successful simulations of hydraulic (XFEM) and natural fracture (continuum, thin weak material) interaction, such as arresting by natural fractures (see e.g. Figure 10), diverting along natural fractures (i.e. opening and shear of natural fractures, see e.g.
Figure 11A), and crossing of hydraulic fractures (see e.g. Figure 11A). Notably, with different material properties/parameters used for the natural fractures (e.g. physical properties/parameters of the natural fractures as described in relation to Figures 5A, 7A and 7B), different 5 interactions between a hydraulic fracture and a natural fracture can be simulated as described below.
Figure 10 shows a diagram 1000 of a simulation output of an arresting of a hydraulic fracture by a natural fracture in accordance with an embodiment. The contour plots show a total displacement in meter for the hydraulic facture 1002 and the natural fracture 1004.
10 As shown in Figure 10, the hydraulic fracture 1002 (left wing) is arrested at the natural fracture 1004 (right wing). With the arrest of the hydraulic fracture 1002 at the natural fracture 1004, the hydraulic fracture 1002 propagates in a direction away from the natural fracture 1004.
Figures 11A, 11B and 11C show diagrams of a simulation output of a hydraulic fracture
Following the definition of the fluid treatment step, interaction between the components of the system can be introduced. The fracture surface and propagation algorithm are defined, and the enrichment nodes within the simulation are also defined.
Although Figure 5 shows the mesh 500, the actual meshing of the model may be applied at this point. For simulation of the hydraulic fracturing using XFEM modelling, a hex type mesh can be implemented. Lastly, a job file is created. Simulation of the hydraulic fracturing is then performed by using the parameters and/or input data defined in the previous steps.
For the simulation of the hydraulic fracturing, the user may also define a step size and a step number to be simulated.
Figure 5C shows a schematic of the mesh 500 with the simulated hydraulic fracturing.
Three different interactions between the hydraulic fractures and the natural fractures are shown in Figure 5C. The line 508 shows a hydraulic fracture being arrested by the natural fracture. The line 510 shows a hydraulic fracture being diverted by the natural fracture.
The line 512 shows a hydraulic fracture crossing the natural fracture.
The simulation outputs of Figures 10 to 11C are generated using hydraulic fracturing with continuum natural fractures (i.e. thin weak conductive material) by using a representation of the mesh 500 (e.g. the mesh 600) in the XFEM model 220. The results of the continuum natural fracture approach as exemplified by the method 300 demonstrated successful simulations of hydraulic (XFEM) and natural fracture (continuum, thin weak material) interaction, such as arresting by natural fractures (see e.g. Figure 10), diverting along natural fractures (i.e. opening and shear of natural fractures, see e.g.
Figure 11A), and crossing of hydraulic fractures (see e.g. Figure 11A). Notably, with different material properties/parameters used for the natural fractures (e.g. physical properties/parameters of the natural fractures as described in relation to Figures 5A, 7A and 7B), different 5 interactions between a hydraulic fracture and a natural fracture can be simulated as described below.
Figure 10 shows a diagram 1000 of a simulation output of an arresting of a hydraulic fracture by a natural fracture in accordance with an embodiment. The contour plots show a total displacement in meter for the hydraulic facture 1002 and the natural fracture 1004.
10 As shown in Figure 10, the hydraulic fracture 1002 (left wing) is arrested at the natural fracture 1004 (right wing). With the arrest of the hydraulic fracture 1002 at the natural fracture 1004, the hydraulic fracture 1002 propagates in a direction away from the natural fracture 1004.
Figures 11A, 11B and 11C show diagrams of a simulation output of a hydraulic fracture
15 crossing a natural fracture in accordance with an embodiment.
Figure 11A shows a perspective view of a displacement contour plot of the simulation output, and Figure 11B shows a perspective view of an opening contour plot of the simulation output for an embodiment where a hydraulic fracture crosses a natural fracture. As shown in Figure 11A, the hydraulic fracture 1102 is shown to have crossed/penetrated through the natural fracture 1104. The displacement contour plot (in meter) of Figure 11A is in relation to a combination of normal and shear displacement of elements of the mesh 500, while the opening contour plot (in meter) of Figure 11B is in relation to normal displacement of enriched element of the mesh 500. As shown in Figure 11B, the hydraulic fracture is represented by 1112. Figure 11B also shows a hole 1114 which is related to the section of the well 712 where fluid is injected for inducing the hydraulic fracture.
Optimizing hydraulic fracturing design generally aims for maximizing stimulated reservoir volume (SRV) and fracture conductivity (i.e. popped opening). The SRV and the fracture conductivity can be optimized by controlling parameters in relation to the fluid injection treatment for hydraulic fracturing operation such as those described in relation to Figure 9. For example, an arresting interaction as shown in relation to Figure 10 typically provides a low SRV while a crossing interaction as shown in relation to Figures 11A-11C
typically provides a high SRV. Therefore, in order to maximize the SRV by having the
Figure 11A shows a perspective view of a displacement contour plot of the simulation output, and Figure 11B shows a perspective view of an opening contour plot of the simulation output for an embodiment where a hydraulic fracture crosses a natural fracture. As shown in Figure 11A, the hydraulic fracture 1102 is shown to have crossed/penetrated through the natural fracture 1104. The displacement contour plot (in meter) of Figure 11A is in relation to a combination of normal and shear displacement of elements of the mesh 500, while the opening contour plot (in meter) of Figure 11B is in relation to normal displacement of enriched element of the mesh 500. As shown in Figure 11B, the hydraulic fracture is represented by 1112. Figure 11B also shows a hole 1114 which is related to the section of the well 712 where fluid is injected for inducing the hydraulic fracture.
Optimizing hydraulic fracturing design generally aims for maximizing stimulated reservoir volume (SRV) and fracture conductivity (i.e. popped opening). The SRV and the fracture conductivity can be optimized by controlling parameters in relation to the fluid injection treatment for hydraulic fracturing operation such as those described in relation to Figure 9. For example, an arresting interaction as shown in relation to Figure 10 typically provides a low SRV while a crossing interaction as shown in relation to Figures 11A-11C
typically provides a high SRV. Therefore, in order to maximize the SRV by having the
16 crossing interaction with the hydraulic fracture intersecting the natural fractures, for example, the injection rate could be increased and the proppant concentration could be decreased (i.e. increasing the fluid velocity). Further, perforation locations for optimizing stress shadowing effects can also be used for optimizing hydraulic fracturing design.
In relation to optimizing hydraulic fracturing operations, Figure 11A shows an example of a simulation output where the SRV is maximized and Figure 11B shows an example of a simulation output where the fracture conductivity is maximized. For achieving optimized hydraulic fracturing operations, both the SRV and the fracture conductivity should be optimized. In cases where the SRV and the fracture conductivity cannot be optimized at the same time, perhaps due geological limitations and/or operational conditions, priority is given to optimizing the fracture conductivity.
Figure 11C shows a top view of the displacement contour plot of Figure 11A.
From Figure 11C, an amount of fault slip can be estimated which can be used for the following risk assessment as described below. As shown in Figure 11C, the hydraulic fracture crosses the natural fracture 1124, and the fault slip is shown as 1126 in this top view.
Fault reactivation and related induced seismic events are potential risks in hydraulic fracturing operation, particularly if the hydraulic fracturing operation is adjacent to major faults. Although there is generally a very low probability of occurrence for an induced seismic event, an induced seismic event carries a very high risk which may result in a shutting down of the entire fracturing operation. This is therefore vital to be able to estimate and mitigate potential risks of fault reactivation and induced seismic events in hydraulic fracturing operations.
However, conventional approaches in assessing risk of fault reactivation and induced seismicity are mostly qualitative. Figures 12A and 12B show plots for assessing risk of fault reactivation and induced seismicity, where Figure 12A shows a conventional critically stressed fault analysis plot and Figure 12B shows a conventional strain energy-based induced seismicity analysis plot. In particular, Figure 12A shows a plot 1200 for critical stress fault analysis which defines the stress along faults for estimating the risk of fault reactivation. For example, if a fault is not critically stressed (e.g. in relation to data points 1206), the risk of fault reactivation is low. If the data associated with a fault is above the friction line 1202, the risk of fault reactivation is high. This risk of fault reactivation may be increased by hydraulic fracturing. For example, when hydraulic fracturing fluid is injected, the original Mohr circle 1204 will be shifted to the left of the
In relation to optimizing hydraulic fracturing operations, Figure 11A shows an example of a simulation output where the SRV is maximized and Figure 11B shows an example of a simulation output where the fracture conductivity is maximized. For achieving optimized hydraulic fracturing operations, both the SRV and the fracture conductivity should be optimized. In cases where the SRV and the fracture conductivity cannot be optimized at the same time, perhaps due geological limitations and/or operational conditions, priority is given to optimizing the fracture conductivity.
Figure 11C shows a top view of the displacement contour plot of Figure 11A.
From Figure 11C, an amount of fault slip can be estimated which can be used for the following risk assessment as described below. As shown in Figure 11C, the hydraulic fracture crosses the natural fracture 1124, and the fault slip is shown as 1126 in this top view.
Fault reactivation and related induced seismic events are potential risks in hydraulic fracturing operation, particularly if the hydraulic fracturing operation is adjacent to major faults. Although there is generally a very low probability of occurrence for an induced seismic event, an induced seismic event carries a very high risk which may result in a shutting down of the entire fracturing operation. This is therefore vital to be able to estimate and mitigate potential risks of fault reactivation and induced seismic events in hydraulic fracturing operations.
However, conventional approaches in assessing risk of fault reactivation and induced seismicity are mostly qualitative. Figures 12A and 12B show plots for assessing risk of fault reactivation and induced seismicity, where Figure 12A shows a conventional critically stressed fault analysis plot and Figure 12B shows a conventional strain energy-based induced seismicity analysis plot. In particular, Figure 12A shows a plot 1200 for critical stress fault analysis which defines the stress along faults for estimating the risk of fault reactivation. For example, if a fault is not critically stressed (e.g. in relation to data points 1206), the risk of fault reactivation is low. If the data associated with a fault is above the friction line 1202, the risk of fault reactivation is high. This risk of fault reactivation may be increased by hydraulic fracturing. For example, when hydraulic fracturing fluid is injected, the original Mohr circle 1204 will be shifted to the left of the
17 plot 1200, as shown by 1208, and will be closer to the fiction line 1202.
Figure 12B shows a plot 1210 of strain energy-based induced seismicity analysis. In this case, a shear displacement along the fault is required for estimating the induced seismicity analysis.
Different lines for representing a magnitude of the slip is shown in the plot 1210. For example, a line 1212 is shown to represent a slip with a magnitude of 0.1mm, while a line 1214 is shown to represent a slip with a magnitude of 1cm. While the analysis in relation to Figure 12A is qualitative and do not provide an accurate approach in determining these potential risks, the analysis of Figure 12B requires a quantitative measure of the shear displacement along the fault, which is generally not readily available and is often estimated in a qualitative manner.
Figures 13A, 13B and 14 describe a method for estimating a magnitude of an induced seismic event using the calculated amount of fault slip in accordance with an embodiment. This method uses the calculated amount of fault slip generated as a result of the hydraulic fracturing, for example as shown in Figure 11C, for providing a more quantitative approach in assessing risk of fault activation and induced seismicity.
Figures 13A and 13B show diagrams of a simulation output of a hydraulic fracture crossing a natural fracture in accordance with an embodiment, where Figure 13A
shows a perspective view of an opening contour plot of the simulation and Figure 13B
shows a top view of a displacement contour plot. Figure 13A is similar to Figure 11B
and is shown here for completeness. As shown in Figure 13B, a crossing interaction between a hydraulic fracture 1312 and a natural fracture 1314 is simulated. A fault slip 1316 can be observed as a result of the interaction between the hydraulic fracture 1312 and the natural fracture 1314. A numerical value for the calculated fault slip can be provided by the XFEM simulation, which can then be used for estimating a magnitude of an induced seismic event as discussed below in relation to Figure 14.
Figure 14 shows an illustration for estimating a magnitude of an induced seismic event by using a calculated amount of fault slip in accordance with an embodiment. A
conventional strain energy-based induced seismicity analysis plot 1400 is reproduced in Figure 14 for this illustration. As shown in Figure 14, by acquiring a quantitative value for the amount of fault slip using the simulation output as shown in Figure 13B, this calculated amount of fault slip can be used as a fault patch size value on the x-axis of the plot 1400. This is shown by a line 1402. Using this fault patch size value, a value for a corresponding earthquake magnitude can be read off the y-axis of the plot 1400 using
Figure 12B shows a plot 1210 of strain energy-based induced seismicity analysis. In this case, a shear displacement along the fault is required for estimating the induced seismicity analysis.
Different lines for representing a magnitude of the slip is shown in the plot 1210. For example, a line 1212 is shown to represent a slip with a magnitude of 0.1mm, while a line 1214 is shown to represent a slip with a magnitude of 1cm. While the analysis in relation to Figure 12A is qualitative and do not provide an accurate approach in determining these potential risks, the analysis of Figure 12B requires a quantitative measure of the shear displacement along the fault, which is generally not readily available and is often estimated in a qualitative manner.
Figures 13A, 13B and 14 describe a method for estimating a magnitude of an induced seismic event using the calculated amount of fault slip in accordance with an embodiment. This method uses the calculated amount of fault slip generated as a result of the hydraulic fracturing, for example as shown in Figure 11C, for providing a more quantitative approach in assessing risk of fault activation and induced seismicity.
Figures 13A and 13B show diagrams of a simulation output of a hydraulic fracture crossing a natural fracture in accordance with an embodiment, where Figure 13A
shows a perspective view of an opening contour plot of the simulation and Figure 13B
shows a top view of a displacement contour plot. Figure 13A is similar to Figure 11B
and is shown here for completeness. As shown in Figure 13B, a crossing interaction between a hydraulic fracture 1312 and a natural fracture 1314 is simulated. A fault slip 1316 can be observed as a result of the interaction between the hydraulic fracture 1312 and the natural fracture 1314. A numerical value for the calculated fault slip can be provided by the XFEM simulation, which can then be used for estimating a magnitude of an induced seismic event as discussed below in relation to Figure 14.
Figure 14 shows an illustration for estimating a magnitude of an induced seismic event by using a calculated amount of fault slip in accordance with an embodiment. A
conventional strain energy-based induced seismicity analysis plot 1400 is reproduced in Figure 14 for this illustration. As shown in Figure 14, by acquiring a quantitative value for the amount of fault slip using the simulation output as shown in Figure 13B, this calculated amount of fault slip can be used as a fault patch size value on the x-axis of the plot 1400. This is shown by a line 1402. Using this fault patch size value, a value for a corresponding earthquake magnitude can be read off the y-axis of the plot 1400 using
18 a line 1404. The method in accordance with the present embodiment shows a performance of a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
Although only certain embodiments of the present invention have been described in detail, many variations are possible in accordance with the appended claims.
For example, features described in relation to one embodiment may be incorporated into one or more other embodiments and vice versa.
Although only certain embodiments of the present invention have been described in detail, many variations are possible in accordance with the appended claims.
For example, features described in relation to one embodiment may be incorporated into one or more other embodiments and vice versa.
Claims (19)
1. A computer implemented method for simulating hydraulic fracturing in a naturally fractured reservoir, the method comprising:
initiating an extended finite element method (XFEM) model for simulating the hydraulic fracturing;
creating a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property;
defining a perforation location in the mesh for initiating hydraulic fracturing; and simulating the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
initiating an extended finite element method (XFEM) model for simulating the hydraulic fracturing;
creating a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property;
defining a perforation location in the mesh for initiating hydraulic fracturing; and simulating the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
2. The method of claim 1, further comprising: defining at least one parameter of the second type of reservoir region, the at least one parameter of the second type of reservoir region includes a length of the natural fracture, a width of the natural fracture, a thickness of the natural fracture, a dip of the natural fracture, or a strike of the natural fracture.
3. The method of claim 1 or claim 2, further comprising: defining at least one parameter of the first material property, the at least one parameter of the first material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
4. The method of any one of claims 1 to 3, further comprising: defining at least one parameter of the second material property, the at least one parameter of the second material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
5. The method of any preceding claim, further comprising: defining a plurality of parameters associated with an injection fluid for the hydraulic fracturing, the plurality of parameters include an injection rate of the fluid, a volume of the fluid, an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid.
6. The method of claim 5, further comprising: optimizing the plurality of parameters associated with the injection fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing.
5 7. The method of any preceding claim, further comprising:
calculating an amount of fault slip generated as a result of the hydraulic fracturing;
and estimating a magnitude of an induced seismic event using the calculated amount of fault slip.
calculating an amount of fault slip generated as a result of the hydraulic fracturing;
and estimating a magnitude of an induced seismic event using the calculated amount of fault slip.
8. The method of claim 7, wherein estimating the magnitude of the induced seismic event comprises performing a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
9. The method of any preceding claim, wherein the mesh comprises a plurality of regions having the second type of material property as defined by the second type of reservoir region.
10. A computer readable medium storing processor executable instructions which when executed on a processor cause the processor to carry out a method according to any one of claims 1 to 9.
11. A system for simulating hydraulic fracturing in a naturally fractured reservoir, the system comprising a processor and a data storing computer program instructions operable to cause the processor to:
initiate an extended finite element method (XFEM) model for simulating the hydraulic fracturing;
create a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property;
define a perforation location in the mesh for initiating hydraulic fracturing;
and simulate the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
initiate an extended finite element method (XFEM) model for simulating the hydraulic fracturing;
create a mesh for the naturally fractured reservoir, the mesh comprises a first type of reservoir region representing a rock matrix having a first material property and a second type of reservoir region representing a natural fracture having a second material property, the first material property being different from the second material property;
define a perforation location in the mesh for initiating hydraulic fracturing;
and simulate the hydraulic fracturing in the naturally fractured reservoir using the XFEM model.
12. The system of claim 11, wherein the data storage further stores computer program instructions operable to cause the processor to: define at least one parameter of the second type of reservoir region, the at least one parameter of the second type of reservoir region includes a length of the natural fracture, a width of the natural fracture, a thickness of the natural fracture, a dip of the natural fracture, or a strike of the natural fracture.
13. The system of claim 11 or claim 12, wherein the data storage further stores computer program instructions operable to cause the processor to: clef ne at least one parameter of the first material property, the at least one parameter of the first material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
14. The system of any one of claims 11 to 13, wherein the data storage further stores computer program instructions operable to cause the processor to: define at least one parameter of the second material property, the at least one parameter of the second material property includes a Young's modulus, a cohesive fracture energy, a permeability or a leak-off coefficient.
15. The system of any one of claims 11 to 14, wherein the data storage further stores computer program instructions operable to cause the processor to: define a plurality of parameters associated with a fluid for the hydraulic fracturing, the plurality of parameters include an injection rate of the fluid, a volume of the fluid, an injection duration of the fluid, a component of the fluid, a viscosity of the fluid and a density of the fluid.
16. The system of claim 15, wherein the data storage further stores computer program instructions operable to cause the processor to: optimize the plurality of parameters associated with the fluid to maximize a stimulated reservoir volume and a fracture conductivity of the hydraulic fracturing.
17. The system of any one of claims 11 to 16, wherein the data storage further stores computer program instructions operable to cause the processor to:
calculate an amount of fault slip generated as a result of the hydraulic fracturing;
and estimate a magnitude of an induced seismic event using the calculated amount of fault slip.
calculate an amount of fault slip generated as a result of the hydraulic fracturing;
and estimate a magnitude of an induced seismic event using the calculated amount of fault slip.
18. The system of claim 17, wherein the data storage further stores computer program instructions operable to cause the processor to: perform a strain energy-based induced seismicity analysis using the calculated amount of fault slip.
19. The system of any one of claims 11 to 18, wherein the mesh comprises a plurality of regions having the second type of material property as defined by the second type of reservoir region.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| MYPI2020005359 | 2020-10-12 | ||
| MYPI2020005359 | 2020-10-12 | ||
| PCT/MY2021/050087 WO2022081003A1 (en) | 2020-10-12 | 2021-10-12 | Method and system for simulating hydraulic fracturing in a naturally fractured reservoir |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA3194382A1 true CA3194382A1 (en) | 2022-04-21 |
Family
ID=81207433
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA3194382A Pending CA3194382A1 (en) | 2020-10-12 | 2021-10-12 | Method and system for simulating hydraulic fracturing in a naturally fractured reservoir |
Country Status (3)
| Country | Link |
|---|---|
| AU (1) | AU2021360104A1 (en) |
| CA (1) | CA3194382A1 (en) |
| WO (1) | WO2022081003A1 (en) |
Family Cites Families (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8494827B2 (en) * | 2009-09-25 | 2013-07-23 | Exxonmobil Upstream Research Company | Method of predicting natural fractures and damage in a subsurface region |
| US9405867B2 (en) * | 2012-06-07 | 2016-08-02 | Dassault Systemes Simulia Corp. | Hydraulic fracture simulation with an extended finite element method |
| US10699034B2 (en) * | 2014-12-31 | 2020-06-30 | Dassault Systemes Simulia Corp. | Flow transition technology |
| US20170051598A1 (en) * | 2015-08-20 | 2017-02-23 | FracGeo, LLC | System For Hydraulic Fracturing Design And Optimization In Naturally Fractured Reservoirs |
| CA3020545A1 (en) * | 2017-10-13 | 2019-04-13 | Uti Limited Partnership | Completions for inducing fracture network complexity |
-
2021
- 2021-10-12 AU AU2021360104A patent/AU2021360104A1/en active Pending
- 2021-10-12 CA CA3194382A patent/CA3194382A1/en active Pending
- 2021-10-12 WO PCT/MY2021/050087 patent/WO2022081003A1/en active Application Filing
Also Published As
| Publication number | Publication date |
|---|---|
| WO2022081003A1 (en) | 2022-04-21 |
| AU2021360104A1 (en) | 2023-04-20 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| Zhang et al. | Fully coupled simulation of a hydraulic fracture interacting with natural fractures with a hybrid discrete‐continuum method | |
| Gupta et al. | Simulation of non‐planar three‐dimensional hydraulic fracture propagation | |
| JP6253899B2 (en) | Hydraulic fracture simulation using extended finite element method | |
| Nagel et al. | Coupled numerical evaluations of the geomechanical interactions between a hydraulic fracture stimulation and a natural fracture system in shale formations | |
| Nagel et al. | Stress shadow evaluations for completion design in unconventional plays | |
| Jiao et al. | A two‐dimensional coupled hydromechanical discontinuum model for simulating rock hydraulic fracturing | |
| AU2014404414B2 (en) | Optimizing multistage hydraulic fracturing design based on three-dimensional (3D) continuum damage mechanics | |
| Zhang et al. | Simulation of hydraulic fracture propagation near a natural fracture using virtual multidimensional internal bonds | |
| Xie et al. | Numerical investigation of effect of natural fractures on hydraulic-fracture propagation in unconventional reservoirs | |
| US20180355701A1 (en) | Hydraulic fracturing simulation | |
| Shrivastava et al. | Formation of complex fracture networks in the wolfcamp shale: calibrating model predictions with core measurements from the hydraulic fracturing test site | |
| Bryant et al. | Arbitrary fracture propagation in heterogeneous poroelastic formations using a finite volume-based cohesive zone model | |
| Taleghani | Fracture re-initiation as a possible branching mechanism during hydraulic fracturing | |
| Ali et al. | Evaluation of the effect of stress-dependent permeability on production performance in shale gas reservoirs | |
| US20150066457A1 (en) | Modeling Fluid Displacement in a Well System Environment | |
| Haddad et al. | Integration of XFEM and CZM to model 3D multiple-stage hydraulic fracturing in quasi-brittle shale formations: solution-dependent propagation direction | |
| Nassir et al. | Prediction and optimization of fracturing in tight gas and shale using a coupled geomechanical model of combined tensile and shear fracturing | |
| Nagel et al. | Quantitative evaluation of completion techniques on influencing shale fracture ‘complexity’ | |
| Cleto et al. | Hydro-mechanical coupled modeling of hydraulic fracturing using the mesh fragmentation technique | |
| US10699034B2 (en) | Flow transition technology | |
| Nagel et al. | Hydraulic fracturing optimization for unconventional reservoirs-the critical role of the mechanical properties of the natural fracture network | |
| Hossain et al. | Volumetric growth and hydraulic conductivity of naturally fractured reservoirs during hydraulic fracturing: a case study using Australian conditions | |
| Rogers et al. | Understanding hydraulic fracture geometry and interactions in pre-conditioning through DFN and numerical modeling | |
| CA3194382A1 (en) | Method and system for simulating hydraulic fracturing in a naturally fractured reservoir | |
| Shakib | RETRACTED: Numerical modeling of hydraulic fracture propagation: Accounting for the effect of stresses on the interaction between hydraulic and parallel natural fractures |