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US20140350906A1 - System and Method for Simulation of Gas Desorption in a Reservoir Using a Multi-Porosity Approach - Google Patents

System and Method for Simulation of Gas Desorption in a Reservoir Using a Multi-Porosity Approach Download PDF

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Publication number
US20140350906A1
US20140350906A1 US14/365,520 US201114365520A US2014350906A1 US 20140350906 A1 US20140350906 A1 US 20140350906A1 US 201114365520 A US201114365520 A US 201114365520A US 2014350906 A1 US2014350906 A1 US 2014350906A1
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types
nodes
reservoir
porosity
pore
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John Edwin Killough
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Landmark Graphics Corp
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Landmark Graphics Corp
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    • 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
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V11/00—Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00
    • 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
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2203/00—Investigating strength properties of solid materials by application of mechanical stress
    • G01N2203/0058—Kind of property studied
    • G01N2203/006—Crack, flaws, fracture or rupture
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2203/00—Investigating strength properties of solid materials by application of mechanical stress
    • G01N2203/0058—Kind of property studied
    • G01N2203/006—Crack, flaws, fracture or rupture
    • G01N2203/0067—Fracture or rupture
    • 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

Definitions

  • Reservoir simulation is an area of reservoir engineering that employs computer models to predict the transport of fluids, such as petroleum, water, and gas, within a reservoir.
  • Reservoir simulators are used by petroleum producers in determining how best to develop new fields, as well as in generating production forecasts on which investment decisions are based in connection with developed fields.
  • Fractured reservoirs present special challenges for simulation because of the multiple porosity systems or structures that may be present in these types of reservoirs.
  • Fractured reservoirs are traditionally modeled by representing the porous media using two co-exiting pore systems or structures interconnected by flow networks, in what is referred to as dual porosity analysis.
  • One type of pore system used in the prior art is the rock matrix, defined with matrix nodes, is characterized by high pore volume and low conductivity.
  • the other type of pore system used in the prior art are induced fractures, and defined with fracture nodes, is characterized by low pore volume and high conductivity.
  • DPSP dual-porosity, single-permeability
  • matrix simulation nodes communicate only with fracture simulation nodes, and the analysis focuses on mass transfer and fluid flow of hydrocarbons between matrix nodes and fracture nodes.
  • fracture nodes can also communicate with other fracures, which communicate with both matrix simulation nodes as well as other fracture simulation nodes.
  • DPDP dual-porosity, dual-permeability
  • matrix simulation nodes communicate with both fracture simulation nodes and as well as other matrix simulation nodes, and the analysis focuses on mass transfer and fluid flow of hydrocarbons between matrix nodes and fracture nodes as well as between matrix nodes and other matrix nodes.
  • nodes refer to the an elemental representation of pore structures within a simulated reservoir
  • zones refer to a collection nodes within the simulated reservoir.
  • Unknowns such as pressures and composition are solved for, typically on a node by node basis, at desired time and/or depth increments.
  • Shale reservoirs typically include large pores or vugs. Vugs are pore spaces that are comparatively larger than pore spaces of the rock matrix. Kerogen resides in this system of vugs within the porous rock matrix.
  • Vugs may or may not be connected to one another.
  • “Separate vugs” are vugs that are interconnected only through the interparticle porosity, i.e., the rock matrix porosity, and are not interconnected to one another (as are matrix pore volumes and fracture pore volumes).
  • “Touching vugs” are vugs that are interconnected to one another. Because of their separate physical and mechanical characteristics, the fluid retention and transport properties of vug pore systems are different from those of both the matrix and fracture systems, and have not heretofore been adequately addressed with analysis utilizing only matrix porosity systems and induced porosity systems. In other words, because of the geologic complexities of shale reservoirs, traditional dual porosity reservoir modeling techniques do not adequately predict mass transfer and fluid flow characteristics of shale reservoirs.
  • FIG. 1 illustrates an example of a reservoir simulation model comprising multiple wells.
  • FIG. 2 illustrates a representation of an example formation comprising a complex network of artificially-induced fractures.
  • FIG. 3 illustrates a simulation grid of a formation comprising a highly deviated wellbore surrounded by natural fractures and a complex network of artificially-induced fractures.
  • one or more embodiments described herein comprise a reservoir simulator including a unique manner of handling gas desorption in shale gas reservoir simulations by rigorously simulating the flow mechanism that occurs therein.
  • each of these four porosity systems is separately characterized and incorporated into the model.
  • the four porosity systems are the matrix porosity system, the induced fracture porosity systems, the natural fracture porosity system and the vug porosity system.
  • the method and system of the invention incorporate natural fracture porosity systems and vug porosity systems.
  • the innermost of these porosity systems is the kerogen vugs, which contain the gas saturation as wetting fluid.
  • the other porosity systems which are the rock matrix, the induced fracture network and the natural fracture network, function as conduits for the gas contained in the kerogen of the shale. Rather than residing in pores throughout the porous rock matrix, the adsorbed gas is generally found only in the kerogen vugs.
  • Natural fractures exist near the vugs, which natural fractures may or may not be open.
  • the framework rock matrix of the porous medium connects the complex natural fractures to the hydraulic induced fractures near the well.
  • the simulation system described in the aforementioned PCT Application No. PCT/US2011/44178 provides a unique tool for simulating general multi-porosity systems in which fluid flow through several porosity systems is modeled using various equations and connectivities in accordance with characteristics of the porosity systems.
  • the embodiments described herein utilize this feature to simulate in a unique fashion the desorption of gases from shale gas reservoirs.
  • the equations provided hereinbelow are transfer functions derived from field observations and laboratory measurements of the desorption process from the kerogen vugs, matrix and fractures of a reservoir. The transfer functions are then utilized by the simulation system to simulate the complex fracture system for the shale as reservoir coupled with the kerogen desorption.
  • vuggy porosity is used to model the kerogen desorption from within a complex fracture system comprised of both induced and natural fractures.
  • FIG. 1 is a block diagram of an exemplary computer system 100 adapted for implementing a reservoir simulation system as described herein.
  • the computer system 100 includes at least one processor 102 , storage 104 , I/O devices 106 , and a display 108 interconnected via a system bus 109 .
  • Software instructions executable by the processor 102 for implementing a reservoir simulation system 110 in accordance with the embodiments described herein, may be stored in storage 104 .
  • the computer system 100 may be connected to one or more public and/or private networks via appropriate network connections.
  • the software instructions comprising the reservoir simulation system 110 may be loaded into storage 104 from a CD-ROM or other appropriate storage media.
  • a portion of the reservoir simulation system 110 is implemented using reservoir simulation software.
  • a “subgrid” data type is used to offer a generalized formulation design.
  • this data type may be Fortran.
  • the subgrid defines the grid domain and interconnectivity properties of the nodes of the various porosity structures. It also tracks various node variables, such as pressure, composition, fluid saturation, etc.
  • Subgrids are designated as being of a particular porosity type, e.g., natural fracture, matrix, induced fracture and vug.
  • the nodes that constitute these grids are correspondingly referred to as natural fracture nodes, matrix nodes, induced fracture nodes and vug nodes.
  • Subgrids of different porosity types occupying the same physical space are said to be “associated”. Connections between porosity types, and in particular, the nodes of the porosity types, are represented as external connections, subgrid to associated subgrids. Internal (or intragrid) connections, and in particular, the nodes of a subgrid, represent flow connections within a porosity type.
  • the modeling of a shale gas reservoir generally involves defining one or more elongated, highly deviated production wellbore, typically thousands of feet in length, with multiple hydraulic fracture zones disposed substantially perpendicular to the wellbore, depending on the stress field in the formation.
  • the stress field is such that a complex fracture system is induced between the large fractures emanating from the well.
  • FIG. 2 One representation of such fractures for an example formation is presented in FIG. 2 and designated by a reference numeral 200 .
  • the representation 200 has been derived from a finite element model of the porous media of the formation following high pressure injection of fracture fluid and proppant.
  • Heavier lines such as those designated by reference numeral 202 , represent fractures induced by hydraulic fracturing, as described above, and which have been modeled in the prior art, i.e., induced fracture porosity systems.
  • Narrower lines and triangular features such as those designated by reference numerals 204 and 206 , respectively, represent a possible finite volume grid with which to model the flow of fluid (primarily gas and water) in the complex fracture network and eventually to a horizontal production wellbore via the induced fracture, as illustrated in FIG. 3 .
  • FIG. 3 illustrates a simulation grid 300 for an elongated, substantially horizontal wellbore 302 , surrounded by induced fractures 304 and a complex natural fracture network 306 .
  • Non-Darcy flow is fluid flow that deviates from Darcy's assumption that fluid flow in the formation will be laminar.
  • Non-Darcy flow is typically observed in high-velocity gas flow induced pressure differentials between the formation and the wellbore. Specifically, when the flow at the wellbore reaches velocities in excess of the Reynolds number for Darcy (or laminar) flow, turbulent flow results and non-Darcy analysis must be utilized.
  • the effect of non-Darcy flow is a rate-dependent skin effect. That is, as the velocity within the wellbore increases, there is an increase in the pressure drop between the wellbore and the fracture.
  • non-Darcy flow results in a significant increase in the pressure drop and therefore plays an important role in properly modeling shale gas production. Because prior art techniques did not tend to model natural fracture pore systems, to the extent non-Darcy flow analysis has been used in the past for reservoir modeling, it has only been utilized to model flow in matrix pore systems and induced fracture systems.
  • Gas desorption for shale development is an important, heretofore underutilized parameter in shale formation modeling. It is estimated that in some shale formations, more than 50% of the gas production will be due to desorption. To the extent gas desorption has been modeled in shale reservoirs, its use has been limited to desorption from the shale matrix. It has not heretofore been applied to desorption analysis from kerogen vugs.
  • V g V L ⁇ P P L + P ( 2 )
  • Vg volume of gas contained in the porous medium
  • V L asymptotic adsorption volume
  • equation (2) results in a modification similar to that for dual porosity, single permeability (“DPSP”), in which a source of gas, i.e., vug nodes, are included in each grid, the volume of which depends on the change in matrix pressure over a timestep in the simulator.
  • DPSP dual porosity, single permeability
  • Sorption time is the time it takes for 63.2% of the gas to be desorbed as calculated using equation (2). In the case of shale gas, this time is generally extremely short and can be ignored. Similarly, the effect of desorption on matrix permeability is generally very small for shale gas and can also be easily ignored.
  • a flowchart is shown illustrating the steps of the process of the invention.
  • the process is utilized to model flow characteristics to a wellbore of a shale reservoir having kerogen vugs and is preferably performed in conjunction with a three dimensional model of a reservoir.
  • reservoir characterization is undertake in which at least three, and preferably four different pore types are described based on fractured shale characteristics.
  • at least three different pore types are identified, selected from the group consisting of natural fracture pore systems, matrix pore systems, induced fracture pore systems and vug pore systems.
  • the pore types are utilized to create one or more subgrids that represent a zone within the reservoir.
  • Each zone includes a plurality of nodes of at least one of the pore types.
  • a subgrid for at least three different pore types is created for a zone.
  • a subgrid for each of the four pore types is created for a zone.
  • connectivities or transfer terms if any, between the nodes are identified and assigned. This may include connectivity between similar nodes within the same subgrid, such as between matrix nodes within a subgrid, or may include connectivity between the nodes of one subgrid and the nodes of another associated subgrid, such as between vug nodes and natural fracture nodes or between matrix nodes and vug nodes.
  • These transfer terms are the parameters that effect flow rates among the various porosity types, such as, for example, initial pore pressures, basis to the nodes of the subgrids.
  • the model consists of at least three different pore types and associated volumes which contain fluids which are to be modeled. In one embodiment, the model consists of at least four different pore types and associated volumes which contain fluids which are to be modeled.
  • know magnitudes for the transfer terms may be assigned, such as, for example, densities, volumes, flow rates and compressibilities.
  • step 408 source terms are now incorporated as boundary conditions to the model in such a way that extraction of the gas is consistent with the wellbore's induced fractures.
  • a wellbore pressure is selected and incorporated into the model. This pressure affects the flow in the induced fractures, which, in turn by virtue of the transfer terms, affects flow between the other porosity types.
  • a linear solver is utilized to solve for any unknown magnitudes of the transfer terms associated with the nodes.
  • non-linear equations are selected to model the reservoir and the subgrids and nodes thereof.
  • the linear solver methodology is applied by subgrid or associated subgrids.
  • the Newton-Raphson method is then applied to linearize these non-linear equations.
  • the linear solver then can be applied to the linear equations to solve for the unknowns. In one embodiment, this step may be iterated utilizing the resultant magnitudes until a desired degree of convergence is achieved between the linear and non-linear equations.
  • time may be incremented and/or the wellbore parameters, such as the boundary conditions of pressure, may be altered to achieve a desired level of mass transfer and fluid flow for the modeled reservoir.
  • a shale reservoir is modeled as described herein to design a well completion plan for a well.
  • the drilling well completion plan includes the selection of a fracturing plan, which may include the selection of fracture zones and their positioning, fracturing fluids, proppants and fracturing pressures.
  • the drilling well completion plan may include selecting a particular trajeocry of the wellbore or selecting a desired wellbore pressure to facilitate mass transfer and fluid flow to the wellbore. Based on the model, a drilling plan may be implemented and a wellbore drilled in accordance with the plan.
  • fracturing may be carried out in accordance with the model to enhance flow from the reservoir to the wellbore.
  • wellbore pressure may be adjusted in accordance with the model to achieve a desired degree of mass transfer and fluid flow.
  • the system of the invention may be utilized during the drilling process on the fly or iteratively to calculate and re-calculate connectivity characteristics of the reservoir over a period of time as parameters change or are clarified or adjusted.
  • the results of the dynamic calculations may be utilized to alter a previously implemented drilling plan.
  • the dynamic calculations may result in the utilization of a heavier or lighter fracturing fluids.

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US20170285221A1 (en) * 2016-01-22 2017-10-05 Saudi Arabian Oil Company Generating dynamically calibrated geo-models in green fields
CN112362556A (zh) * 2020-11-13 2021-02-12 重庆大学 获得煤矿采动稳定区渗透系数连续函数的方法
CN117077577A (zh) * 2023-10-17 2023-11-17 中国石油大学(华东) 一种适用于低渗透裂缝性油藏的快速模拟及优化方法
US11867869B2 (en) 2021-02-11 2024-01-09 Saudi Arabian Oil Company Multiple porosity micromodel
CN120600132A (zh) * 2025-08-07 2025-09-05 中国石油大学(华东) 一种基于预设目标孔隙参数生成三维孔隙原子模型的方法及系统

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US10012064B2 (en) 2015-04-09 2018-07-03 Highlands Natural Resources, Plc Gas diverter for well and reservoir stimulation
US10344204B2 (en) 2015-04-09 2019-07-09 Diversion Technologies, LLC Gas diverter for well and reservoir stimulation
US10982520B2 (en) 2016-04-27 2021-04-20 Highland Natural Resources, PLC Gas diverter for well and reservoir stimulation
US12252973B2 (en) 2019-03-06 2025-03-18 Schlumberger Technology Corporation Modeling diffusion and expulsion of hydrocarbons in kerogen
CN110593865B (zh) * 2019-09-29 2022-07-29 中国石油集团川庆钻探工程有限公司 一种油藏缝洞特征参数试井解释方法
US12385818B2 (en) 2023-02-14 2025-08-12 Saudi Arabian Oil Company Modeling gas desorption in a subsurface reservoir
CN119827739B (zh) * 2023-10-12 2025-10-24 中国石油化工股份有限公司 一种孔隙结构对页岩油渗吸影响的微流控实验方法及系统

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US20170285221A1 (en) * 2016-01-22 2017-10-05 Saudi Arabian Oil Company Generating dynamically calibrated geo-models in green fields
US10359542B2 (en) * 2016-01-22 2019-07-23 Saudi Arabian Oil Company Generating dynamically calibrated geo-models in green fields
CN112362556A (zh) * 2020-11-13 2021-02-12 重庆大学 获得煤矿采动稳定区渗透系数连续函数的方法
US11867869B2 (en) 2021-02-11 2024-01-09 Saudi Arabian Oil Company Multiple porosity micromodel
CN117077577A (zh) * 2023-10-17 2023-11-17 中国石油大学(华东) 一种适用于低渗透裂缝性油藏的快速模拟及优化方法
CN120600132A (zh) * 2025-08-07 2025-09-05 中国石油大学(华东) 一种基于预设目标孔隙参数生成三维孔隙原子模型的方法及系统

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CA2858319A1 (en) 2013-06-20
AR089218A1 (es) 2014-08-06
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WO2013089784A1 (en) 2013-06-20
CA2858319C (en) 2019-07-30
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MX341255B (es) 2016-08-09
EP2791858A4 (en) 2016-11-16

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