Shale gas fractured horizontal well recoverable reserves evaluation method and system based on double-zone composite material balance

Abstract

The application provides a shale gas fracturing horizontal well recoverable reserve evaluation method and system based on a double-zone composite material balance, which is based on basic data of a shale gas fracturing horizontal well, and pressure propagation distance of a fracturing reconstruction zone and distance of pressure drop funnel propagation to an unreconstructed zone outside are calculated according to time step information and a pressure propagation mechanism, and then dynamic reserves of the double-zone are calculated, and shale gas reservoir material balance models are respectively established; shale gas well productivity coefficients and crossflow coefficients of the outer zone to the SRV zone of the fracturing horizontal well are calculated in combination with the basic data; current iteration step production is calculated and cumulative production data is calculated in combination with the shale gas well productivity coefficients and the crossflow coefficients of the outer zone to the SRV zone of the fracturing horizontal well based on average formation pressure results of the shale gas reservoir double-zone coupling material balance model iterative solution. By using the scheme, the problems of application limitation and low operation efficiency of the prior art can be overcome, and productivity mechanism dynamic prediction production data of the reconstruction zone and the outer zone are considered.

Description

Technical Field

[0001] This invention relates to the field of shale gas exploration and development technology, and in particular to a method and system for evaluating the recoverable reserves of shale gas fractured horizontal wells based on dual-zone composite material balance. Background Technology

[0002] Shale gas reservoirs, as an important type of unconventional gas reservoir, possess unique characteristics in their formation and enrichment. Compared to conventional natural gas reservoirs, shale, as a source rock, has a stronger hydrocarbon generation capacity, thus exhibiting self-generating, self-storing, and self-sealing characteristics. In shale gas reservoirs, shale simultaneously serves as a source rock, reservoir, and even caprock. The unique formation process of shale gas determines the complexity of its microscopic pore structure, leading to a diversity of shale gas occurrence states. This multi-scale, complex pore structure further means that shale gas production from shale gas reservoirs is the result of a combination of multiple mechanisms.

[0003] Shale porosity is one of the important parameters characterizing shale gas reserves. Compared with ordinary reservoirs, shale reservoirs are ultra-tight reservoirs with extremely low porosity and permeability. Currently, a standardized system has been established for evaluating the physical properties of shale cores. The shale core measurement method developed by the U.S. Natural Gas Research Institute (GRI) in 1986 is primarily used for evaluating shale reservoir properties. This method can measure the total porosity of the shale matrix and the gas-bearing porosity of the shale reservoir. The reservoir space of shale and mudstone can be broadly divided into two categories: matrix porosity and natural fractures. Matrix porosity can be further divided into organic porosity and inorganic porosity according to its origin.

[0004] The unique pore types of shale gas reservoirs determine the diversity of shale gas occurrence states. Research shows that the storage mechanism of shale gas differs significantly from that of conventional natural gas. Currently, the consensus regarding the occurrence states of shale gas is that, apart from a very small amount existing in a dissolved state (a small amount dissolved in kerogen, bituminous matter, liquid hydrocarbons, and residual water), most shale gas exists primarily in two forms: adsorbed and free (i.e., in a free state existing in the micropores and fractures of the shale matrix, and adsorbed on the surface of the organic matter in the shale matrix). Shale gas reservoirs have complex pore structures, possessing a dual multi-scale pore medium of matrix and natural fractures, resulting in diverse occurrence modes. Free gas and adsorbed gas coexist. The matrix is ​​the primary storage space for natural gas, the natural fracture system is its main migration channel, and horizontal well volumetric fracturing is the primary development method for shale gas reservoirs. The complex pore structure of shale gas reservoirs determines their unique seepage patterns. From a macroscopic to a microscopic perspective, the processes involved in shale gas production include: the flow of shale gas in artificially fractured and natural fractures; the seepage of shale gas in the micropores of the matrix; the diffusion of shale gas in nanoscale pores; and the desorption of shale gas from the surface of organic matter particles.

[0005] For shale gas reservoirs, multi-stage fracturing often creates a fracturing and remodeling zone around the horizontal well, called the volumetric fracturing zone (SRV zone). Hydraulic fracturing can increase the permeability of natural fractures, expand the contact area between the matrix and fractures, and improve reservoir properties. Generally, the early and mid-stage production of shale gas wells mainly comes from the SRV zone, but in the later stages of production, the contribution of the unfractured zone to gas production becomes increasingly significant. The seepage characteristics of multi-stage fracturing horizontal wells in shale gas reservoirs differ from those in conventional gas reservoirs, mainly in that: the permeability of the shale matrix is ​​generally between a few and several hundred nanocities, the pressure propagation speed is slow, and the unsteady flow time is long. The time of inter-well interference mainly depends on the well spacing; if the fractures between wells are not directly connected, the pressure propagation speed between wells is slow, and the time required to enter the boundary control flow stage is generally extremely long.

[0006] Currently, the methods for evaluating the recoverable reserves of shale gas fractured horizontal wells generally rely on production decline curve analysis or production-pressure instability analysis (RTA). The former requires the gas well to enter the decline phase, and the decline period generally needs to be more than one year before the uncertainty of predicting recoverable reserves can be extrapolated in stages. The latter requires the gas well to have been in trial production for more than six months to one year, and the geological and fracturing parameters of the shale gas fractured horizontal well are determined by fitting the production history to predict the gas well's production capacity. The model requires complex solutions and processing of variable production and pressure superposition. It is evident that the application of existing technologies has limitations, and the calculation and operation are time-consuming, which cannot well meet the requirements of shale gas exploration and development engineering.

[0007] The information disclosed in the background section of this invention is intended only to enhance the understanding of the general background of this invention, and should not be construed as an admission or in any way implying that such information constitutes prior art known to those skilled in the art. Summary of the Invention

[0008] To address the aforementioned problems, this invention provides a method for evaluating the recoverable reserves of shale gas fractured horizontal wells based on dual-zone composite material balance. This method effectively overcomes the limitations of existing technologies and their low computational efficiency, while also considering the dynamic prediction of production data based on the production mechanisms of both the stimulated and outer zones. Based on fundamental data from shale gas fractured horizontal wells, this method calculates the pressure propagation distance from the fractured stimulated zone and the distance the pressure drop funnel propagates to the surrounding unstimulated zone according to time step information and pressure propagation mechanisms. This allows for the calculation of dynamic reserves in both zones, establishing material balance models for the shale gas reservoir. The method also calculates the shale gas well productivity coefficient and the SRV (Self-Recovery Volume) flow coefficient from the outer zone to the fractured horizontal well, based on the fundamental data. Finally, based on the average formation pressure results obtained through iterative solutions of the dual-zone coupled material balance model, the method calculates the production rate for the current iteration step and the cumulative production data, combining the shale gas well productivity coefficient and the SRV flow coefficient from the outer zone to the fractured horizontal well. Preferably, in one embodiment, the method includes:

[0009] Step S100: Prepare basic data for shale gas fracturing horizontal wells, including basic geological parameters, adsorption and desorption parameters, shale gas parameters, and multi-stage fracturing parameters;

[0010] Step S200: Set the calculation time step, and calculate the pressure propagation distance of the fracturing zone and the distance of the pressure drop funnel from the outer unmodified zone according to the time step information and the pressure propagation mechanism;

[0011] Step S300: Calculate the dynamic reserves mobilized in the fracturing zone and the outer zone based on the pressure propagation distance, and then establish shale gas reservoir material balance models for the fracturing zone and the surrounding unfracturing zone respectively;

[0012] Step S400: Calculate the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the external fractured horizontal well based on the basic data;

[0013] Step S500: Based on the average formation pressure results obtained by iteratively solving the dual-zone coupled material balance model of the shale gas reservoir in the fracturing zone and the surrounding unfracturing zone, the production data of the current iteration step is calculated by combining the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the fracturing horizontal well in the outer zone, and then the cumulative production data is calculated.

[0014] Furthermore, in one embodiment, the basic geological parameters in step S100 include: initial formation pressure, relative density of natural gas, gas reservoir temperature, reservoir thickness, total porosity, gas saturation, water saturation, and shale porosity compressibility.

[0015] Adsorption and desorption parameters include Langmuir pressure, Langmuir volume, and shale density;

[0016] Multi-stage fracturing parameters include horizontal well length, number of fracturing fractures, half-length of the main fracture, and conductivity of the main fracture.

[0017] The shale gas parameters are calculated using the shale gas PVT parameters based on the relative density of natural gas using the corresponding property model.

[0018] In an optional embodiment, in step S200, the pressure propagation distance of the fracturing zone is calculated using the following formula:

[0019]

[0020] In the formula, Y inv1 K1 represents the pressure propagation distance in the fracturing zone, t represents time, φ represents reservoir porosity, μ represents natural gas viscosity, and c represents the permeability of the fracturing zone in the horizontal well. t L represents the overall compressibility coefficient of shale; the subscript i indicates that the parameter value is taken under the initial state. s This indicates the spacing between adjacent cracks.

[0021] In one embodiment, the distance the pressure drop funnel in the fracturing zone propagates to the surrounding untreated zone is calculated using the following formula:

[0022]

[0023] In the formula, Y inv2 K1 represents the distance the pressure drop funnel from the fracturing zone propagates to the surrounding untreated zone; K2 represents the permeability of the SRV zone of the fracturing horizontal well; t represents time. elf c is the pressure disturbance time between adjacent main fractures; ti μ is the overall compressibility coefficient under initial pressure. i Y represents the viscosity of natural gas at the initial pressure. e Le is the model width; Le is the length of the horizontal section of the horizontal well; n f This represents the number of cracks.

[0024] Furthermore, in one embodiment, in step S300, the dynamic reserves used in the fracturing zone at the current time step and the dynamic reserves used in the unfracturing zone at the current time step are calculated using the volume method and the volumetric method, respectively, based on the pressure propagation distance and the distance propagated from the pressure drop funnel of the fracturing zone to the surrounding unfracturing zone.

[0025] In a preferred embodiment, in step S300, the dynamic reserves G1 utilized in the fracturing zone at the current time step are calculated using the following formula:

[0026]

[0027] The dynamic reserves G2 currently used in the unfractured zone are calculated using the following formula:

[0028]

[0029] In the formula, h is the thickness of the shale reservoir, in meters; X f B represents the half-length of a fracture in a horizontal shale gas fracturing well, in meters. gi L is the natural gas volume factor under the initial formation pressure; s The distance between adjacent fractures in a shale gas fracturing horizontal well is in meters (m).

[0030] Optionally, in one embodiment, in step S300, a material balance model for the fracturing zone is established as follows:

[0031]

[0032] The following material balance model for the unfractured outer perimeter zone is established:

[0033]

[0034] in,

[0035]

[0036] In the formula, p1 is the current average formation pressure in the fracturing zone; p2 is the current average formation pressure in the surrounding unfracturing zone; p i The original formation pressures a and c are... f S is the pore compressibility coefficient of shale; gi G1 represents the original gas saturation; G2 represents the dynamic reserves used in the current time step of the fracturing zone; G3 represents the dynamic reserves used in the current time step of the unfracturing zone; and p represents the current formation pressure. sc Standard pressure; z * Z(p) is the deviation coefficient for corrected formation pressure p; Z is the deviation coefficient for natural gas. sc T is the deviation coefficient of natural gas under standard conditions; T is the temperature of the shale gas reservoir; T sc Temperature under standard conditions; Φ is total porosity; ρ b V is the density of shale; L Langmuir isothermal adsorption volume for shale gas; P L Langmuir isothermal adsorption Langmuir pressure for shale gas; c w s is the formation water compressibility coefficient; wi is the compressibility coefficient of bound water.

[0037] Specifically, in a preferred embodiment, in step S400, the shale gas well productivity coefficient is calculated using the following formula:

[0038]

[0039] In the formula, WI g K1(p) represents the natural gas production coefficient of the fractured horizontal well; K1(p) represents the permeability of the fractured zone, which is a function of pressure p; h represents the shale reservoir thickness; uppercase T represents temperature; S t This represents the total skin coefficient.

[0040] Optionally, in one embodiment, in step S400, based on the distance the pressure drop funnel from the fracturing zone propagates to the surrounding untreated zone and combined with basic data, the flow coefficient from the outer zone to the fracturing horizontal well SRV zone is calculated using the following formula:

[0041]

[0042] In the formula, WI g,12 The crossflow coefficient from the outer zone to the SRV zone of the fracturing horizontal well. To harmonize penetration rates between internal and external zones, K2 represents the penetration rate in the outer zone.

[0043] Based on other aspects of the methods described in any one or more of the foregoing embodiments, the present invention also provides a storage medium storing program code that can implement the methods described in any one or more of the foregoing embodiments.

[0044] Based on the application aspects of the methods described in any one or more of the above embodiments, the present invention also provides a shale gas fracturing horizontal well recoverable reserves evaluation system based on dual-zone composite material balance, which performs the methods described in any one or more of the above embodiments.

[0045] Compared with the closest prior art, the present invention also has the following beneficial effects:

[0046] This invention provides a method for evaluating recoverable reserves in shale gas fractured horizontal wells based on dual-zone composite material balance. The method involves preparing basic data for the shale gas fractured horizontal well, setting a computation time step, and calculating the pressure propagation distance of the fractured zone and the distance the pressure drop funnel propagates to the surrounding unaffected zone according to the pressure propagation formula. Based on the pressure propagation distance, the dynamic reserves utilized in the fractured zone and the outer zone are calculated, and material balance models for the shale gas reservoir in the fractured zone and the surrounding unaffected zone are established respectively. The method considers the impact of adsorbed gas desorption and permeability stress sensitivity on production capacity evaluation, and further analyzes the impact on unsteady-state production capacity prediction from the perspectives of the SRV-affected zone and the surrounding unaffected zone of the shale gas fractured horizontal well.

[0047] By combining basic data, the production capacity coefficient of shale gas fractured horizontal wells and the SRV (Self-Rift Vent) crossflow coefficient of fractured horizontal wells in the outer zone are calculated. Based on the solution results of the shale gas reservoir material balance model in the fractured and unfractured outer zones, the production data at the current time step is calculated using the production capacity coefficient of the fractured horizontal wells and the SRV crossflow coefficient of fractured horizontal wells in the outer zone, and then the cumulative production data is calculated. By iteratively calculating the average formation pressure and updating the parameters, and performing dynamic calculations at different time steps, the dynamic data of production, bottom hole pressure, and formation pressure changing over time can be reliably predicted.

[0048] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0049] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0050] Figure 1This is a schematic diagram of the control range of a single well in a multi-stage fracturing horizontal shale gas well provided in an embodiment of the present invention;

[0051] Figure 2 This is a flowchart illustrating a method for evaluating recoverable reserves in shale gas fracturing horizontal wells based on dual-zone composite material balance, provided in an embodiment of the present invention.

[0052] Figure 3 This is a schematic diagram of pressure propagation in a single fracture unit of the SRV zone of a multi-stage fractured horizontal well in the shale gas reservoir recovery reserve evaluation method based on dual-zone composite material balance provided in this embodiment of the invention.

[0053] Figure 4 This is a schematic diagram of the coupling between the inner and outer zones of a single fracture unit in a shale gas multi-stage fracturing horizontal well, in the shale gas fracturing horizontal well recoverable reserve evaluation method based on dual-zone composite material balance provided in the embodiments of the present invention.

[0054] Figure 5 This is an example diagram of the production curve of the Jiaoye C-HF well, an implementation case of the method for evaluating recoverable reserves of shale gas fracturing horizontal wells based on dual-zone composite material balance in this invention.

[0055] Figure 6 This is an example diagram of the production history fitting of the Jiaoye C-HF well, a case study of the shale gas fracturing horizontal well recoverable reserves evaluation method based on dual-zone composite material balance in this invention.

[0056] Figure 7 This is an example diagram of the material balance production capacity prediction of the Jiaoye C-HF well, which is an embodiment of the method for evaluating recoverable reserves of shale gas fracturing horizontal wells based on dual-zone composite material balance in this invention. Detailed Implementation

[0057] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples. Those skilled in the art will then fully understand how the present invention uses technical means to solve technical problems and achieve technical effects, and will be able to implement the present invention specifically based on the above-described implementation process. It should be noted that, as long as there is no conflict, the various embodiments and features of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0058] Although the flowchart describes the operations as sequential processes, many of these operations can be performed in parallel, concurrently, or simultaneously. The order of the operations can be rearranged. A process can terminate when its operation is complete, but it may also have additional steps not included in the diagram. A process can correspond to a method, function, procedure, subroutine, subroutine, etc.

[0059] Computer equipment includes user equipment and network equipment. User equipment or clients include, but are not limited to, computers, smartphones, and PDAs (Personal Digital Assistants); network equipment includes, but is not limited to, a single network server, a server group consisting of multiple network servers, or a cloud based on cloud computing consisting of a large number of computers or network servers. Computer equipment can operate independently to implement this invention, or it can connect to a network and implement this invention through interaction with other computer devices within the network. The network in which the computer equipment resides includes, but is not limited to, the Internet, wide area networks (WANs), metropolitan area networks (MANs), local area networks (LANs), and VPN networks.

[0060] The terms “first,” “second,” etc., may be used herein to describe various units, but these units should not be limited by these terms; they are used merely to distinguish one unit from another. The term “and / or” as used herein includes any and all combinations of one or more of the associated listed items. When a unit is referred to as “connected” or “coupled” to another unit, it may be directly connected or coupled to said other unit, or there may be intermediate units present.

[0061] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms “a” and “an” as used herein are also intended to include the plural. It should also be understood that the terms “comprising” and / or “including” as used herein specify the presence of the stated features, integers, steps, operations, units, and / or components, without excluding the presence or addition of one or more other features, integers, steps, operations, units, components, and / or combinations thereof.

[0062] Shale gas refers to unconventional natural gas that accumulates primarily in free and adsorbed states within organic-rich black mudstone and shale, and possesses commercial exploitation value. As an important type of unconventional gas reservoir, shale gas reservoirs exhibit unique characteristics in their formation and enrichment. Compared to conventional natural gas reservoirs, shale, as a source rock, has a stronger hydrocarbon generation capacity, thus shale gas reservoirs possess self-generating, self-storing, and self-sealing characteristics. In shale gas reservoirs, shale simultaneously serves as a source rock, reservoir, and even caprock. The unique formation process of shale gas determines the complexity of its microscopic pore structure, leading to a diversity of shale gas occurrence states. The multi-scale complex pore structure of shale gas reservoirs also means that shale gas production is the result of multiple combined mechanisms.

[0063] Shale porosity is one of the important parameters characterizing shale gas reserves. Compared with ordinary reservoirs, shale reservoirs are ultra-tight reservoirs with extremely low porosity and permeability. Data shows that shale reservoir thickness is generally 15–100 m, shale reservoir porosity varies from 2% to 15%, and the permeability of natural fractures in the reservoir is generally less than 0.001 × 10⁻⁶ m. -3 μm 2 As one of the earliest countries to develop shale gas, the United States has established a standardized system for evaluating the physical properties of shale cores. In North America, the primary method used for evaluating the physical properties of shale reservoirs is the shale core measurement method developed by the Natural Gas Research Institute (GRI) in 1986. This method can measure not only the total porosity of the shale matrix but also the gas-bearing porosity of the shale reservoir. The reservoir space of mudstone and shale can be broadly divided into two categories: matrix porosity and natural fractures. Matrix porosity, based on its origin, can be further divided into organic porosity and inorganic porosity.

[0064] The unique pore types of shale gas reservoirs determine the diversity of shale gas occurrence states. A review of existing domestic and international data reveals significant differences between the storage mechanisms of shale gas and conventional natural gas. Currently, the consensus both domestically and internationally regarding the occurrence states of shale gas is that, apart from a very small amount existing in a dissolved state (a small amount dissolved in kerogen, bituminous substances, liquid hydrocarbons, and residual water), most shale gas exists primarily in two forms: adsorbed and free (i.e., in a free state existing in the micropores and fractures of the shale matrix, and in an adsorbed state adsorbed on the surface of the organic matter in the shale matrix).

[0065] Shale gas reservoirs have complex pore structures, possessing a dual multi-scale porous medium of matrix and natural fractures. They exhibit diverse occurrence modes, with free gas and adsorbed gas coexisting. The matrix is ​​the primary storage space for natural gas, while the natural fracture system serves as its main migration pathway. Shale matrix permeability typically ranges from a few to several hundred nadarses, resulting in low natural production capacity of gas wells and lacking industrial exploitation value. Horizontal well volumetric fracturing is the primary development method for shale gas reservoirs.

[0066] The complex pore structure of shale gas reservoirs determines their unique seepage patterns. From a macroscopic to a microscopic perspective, the processes involved in shale gas production include: the flow of shale gas in artificially fractured and natural fractures; the seepage of shale gas in the micropores of the matrix; the diffusion of shale gas in nanoscale pores; and the desorption of shale gas from the surface of organic matter particles.

[0067] For shale gas reservoirs, multi-stage fracturing often creates a fracturing influence zone around the horizontal well, called the volumetric fracturing zone (SRV zone). Hydraulic fracturing can increase the permeability of natural fractures, expand the contact area between the matrix and fractures, and improve reservoir properties. Generally, the early and mid-stage production of shale gas wells mainly comes from the SRV zone, but in the later stages of production, the contribution of the unfractured zone to gas production becomes increasingly significant.

[0068] The seepage characteristics of multi-stage fractured horizontal wells in shale gas reservoirs differ from those of conventional gas reservoirs, mainly in that: the permeability of the shale matrix is ​​generally between a few and several hundred nanocities, the pressure propagation velocity is slow, and the unsteady flow time is long. The time of inter-well interference mainly depends on the well spacing. If the fractures between wells are not directly connected, the pressure propagation velocity between wells is slow, and the time required to enter the boundary control flow stage is generally extremely long.

[0069] Currently, the methods for evaluating the recoverable reserves of shale gas fractured horizontal wells generally rely on production decline curve analysis or production-pressure instability analysis (RTA). The former requires the gas well to enter the decline phase, and the decline period generally needs to be more than one year before the uncertainty of predicting recoverable reserves can be extrapolated in stages. The latter requires the gas well to have been in trial production for more than six months to one year, and the geological and fracturing parameters of the shale gas fractured horizontal well are determined by fitting the production history to predict the gas well's production capacity. The model requires complex solutions and processing of variable production and pressure superposition. It is evident that the application of existing technologies has limitations, and the calculation and operation are time-consuming, which cannot well meet the requirements of shale gas exploration and development engineering.

[0070] To address the aforementioned issues, this invention provides a method and system for evaluating the recoverable reserves of shale gas fractured horizontal wells based on dual-zone composite material balance. This method, targeting shale gas fractured horizontal wells, considers the influence of free gas, adsorbed gas, and the composite zone formed by volumetric fracturing of the horizontal well, establishing a dual-zone composite material balance method for evaluating the production capacity (recoverable reserves) of shale gas fractured horizontal wells. When applied, this invention can take into account the impact of adsorbed gas desorption and permeability stress sensitivity on production capacity evaluation in shale gas reservoirs. Furthermore, it analyzes the impact on unsteady-state production capacity prediction from the perspectives of the SRV-stimulated zone and the surrounding unstimulated zone of the shale gas fractured horizontal well. It can predict dynamic data on the changes in production, bottom hole pressure, and formation pressure over time for production conditions such as constant production, constant pressure production, and variable production and pressure.

[0071] The following describes the detailed flow of the method according to an embodiment of the present invention with reference to the accompanying drawings, the steps of which can be executed in a computer system containing, for example, a set of computer-executable instructions. Although the logical order of the steps is shown in the flowchart, in some cases, the steps shown or described may be performed in a different order than that shown here.

[0072] Example 1

[0073] Figure 1 This diagram illustrates the control area of ​​a single shale gas fracturing horizontal well, consisting of a fracturing zone (SRV) and an unfracturing zone. In practical applications, shale gas is produced through matrix adsorption desorption, diffusion, and seepage, flowing into the wellbore via natural and hydraulic fractures. Initially, the produced gas is mainly free gas. As formation pressure decreases, adsorbed gas begins to desorb in large quantities, and the well gradually enters a low-production phase, with the production decline rate gradually stabilizing. When the well is first put into production, gas production mainly comes from the fracturing zone (SRV). As pressure interference begins between adjacent fractures in the SRV and formation pressure decreases significantly, the crossflow supply from the unfracturing zone surrounding the SRV gradually increases.

[0074] Figure 2 This diagram illustrates a flowchart of the method for evaluating recoverable reserves in shale gas fracturing horizontal wells based on dual-zone composite material balance, as provided in Embodiment 1 of the present invention. (Refer to...) Figure 2 As can be seen, the method includes the following steps.

[0075] Step S100: Prepare basic data for shale gas fracturing horizontal wells, including basic geological parameters, adsorption and desorption parameters, shale gas parameters, and multi-stage fracturing parameters;

[0076] Step S200: Set the calculation time step, and calculate the pressure propagation distance of the fracturing zone and the distance of the pressure drop funnel from the outer unmodified zone according to the pressure propagation mechanism based on the time step information;

[0077] Step S300: Calculate the dynamic reserves mobilized in the fracturing zone and the outer zone based on the pressure propagation distance, and then establish shale gas reservoir material balance models for the fracturing zone and the surrounding unfracturing zone respectively;

[0078] Step S400: Calculate the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the external fractured horizontal well based on the basic data;

[0079] Step S500: Based on the average formation pressure results obtained by iteratively solving the dual-zone coupled material balance model of the shale gas reservoir in the fracturing zone and the surrounding unfracturing zone, the production data of the current iteration step is calculated by combining the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the fracturing horizontal well in the outer zone, and then the cumulative production data is calculated.

[0080] This invention addresses shale gas fractured horizontal wells, considering the influence of the composite zone formed by free gas, adsorbed gas, and volumetric fracturing in the horizontal well. It establishes a dual-zone composite material balance production capacity (recoverable reserves) evaluation method for shale gas fractured horizontal wells. The method has at least the following advantages: 1. It effectively considers the impact of adsorbed gas desorption and permeability stress sensitivity on production capacity evaluation in shale gas reservoirs; 2. It considers the impact of the SRV-stimulated zone and the surrounding unstimulated zone of the shale gas fractured horizontal well on unsteady-state production capacity prediction; 3. It can predict the changes in production, bottom hole pressure, and formation pressure over time for constant production, constant pressure production, and variable production / variable pressure production conditions.

[0081] Before production capacity forecasting, basic parameters of shale gas fractured horizontal wells are collected. Therefore, in one embodiment, basic data of shale gas fractured horizontal wells are prepared in step S100, including basic geological parameters, adsorption and desorption parameters, shale gas PVT parameters, and multi-stage fracture parameters.

[0082] In practical applications, basic data can include data from testing, collecting, and setting basic geological parameters, adsorption and desorption parameters, shale gas PVT parameters, and horizontal well multi-stage fracturing parameters.

[0083] For example, basic geological parameters may include initial formation pressure, relative density of natural gas, reservoir temperature, reservoir thickness, total porosity, gas saturation, water saturation, shale porosity compressibility, and reservoir permeability. Adsorption-desorption parameters may include Randle pressure, Randle volume, and shale density; horizontal well multi-stage fracturing parameters may include horizontal well length, number of fracturing fractures, half-length of the main fracture, and conductivity of the main fracture. Shale gas PVT property parameters are calculated from the corresponding property model based on the relative density of natural gas.

[0084] Next, initialize the parameter tables required for production capacity evaluation, mainly including the shale gas PVT attribute parameter table, including the attribute interpolation table between the deviation coefficient, volume coefficient, compressibility coefficient, density, viscosity and pressure, the pressure-pseudo-pressure interpolation table and the material balance equation interpolation table, and initialize the model parameters at time t=0.

[0085] Further, in step S200, the calculation time step is set, and the pressure propagation distance Y is calculated according to the pressure propagation formula based on the current time step. inv1 To determine whether pressure interference occurs between adjacent cracks, Y inv1 The calculation is divided into two cases, such as Figure 3 As shown.

[0086] In an optional embodiment, the current time step is set to t = t + Δt; the pressure propagation distance Y in the SRV region is calculated based on the current time. inv1 The distance Y from the SRV region pressure drop funnel to the outer unmodified area inv2 .

[0087] like Figure 4 As shown, in the preferred embodiment, the pressure propagation distance of the fracturing zone is calculated using the following formulas:

[0088]

[0089] In the formula, Y inv1 K1 represents the pressure propagation distance in the fracturing zone, K1 represents the permeability of the fracturing zone in the horizontal well, t represents time, φ represents reservoir porosity (decimal), μ represents natural gas viscosity (cP), and c t L represents the overall compressibility coefficient of shale; the subscript i indicates that the parameter value is taken under the initial state. s This indicates the spacing between adjacent cracks.

[0090] The distance from the pressure drop funnel in the fracturing zone to the surrounding untreated zone is calculated using the following formula:

[0091]

[0092] In the formula, Y inv2 K1 represents the distance the pressure drop funnel from the fracturing zone propagates to the surrounding untreated zone; K2 represents the permeability of the SRV zone of the fracturing horizontal well; t represents time. elf c is the pressure disturbance time between adjacent main fractures; ti μ is the overall compressibility coefficient under initial pressure. i Y represents the viscosity of natural gas at the initial pressure. e Le is the model width; Le is the length of the horizontal section of the horizontal well; n f x represents the number of cracks. f This is half the length of the fracture in a horizontal well for shale gas fracturing.

[0093] Further, step S300 is executed to calculate the dynamic reserves utilized in the fracturing zone and the outer zone based on the pressure propagation distance, and then establish shale gas reservoir material balance models for the fracturing zone and the surrounding unfracturing zone, respectively. Specifically, material balance models for shale gas reservoirs in the fracturing zone and the surrounding unfracturing zone are established based on the current time step pressure propagation distance.

[0094] In practical applications, the pressure propagation distance is the pressure propagation radius, and G1 is the dynamic reserve used in the current time step of the fracturing zone. Based on the pressure propagation radius Y... inv1 Calculated using the volume method and the capacity method:

[0095]

[0096] G2 represents the dynamic reserves currently utilized in the unfractured zone, based on the pressure propagation radius Y. inv2 Calculated using the volume method and the capacity method:

[0097]

[0098] In the formula, h is the thickness of the shale reservoir, in meters; X f B represents the half-length of a fracture in a horizontal shale gas fracturing well, in meters. gi L is the natural gas volume factor under the initial formation pressure; s The distance between adjacent fractures in a shale gas fracturing horizontal well is in meters (m).

[0099] Furthermore, based on the dynamic reserves utilized at the current time step in the fracturing stimulation zone, the following material balance model for the fracturing stimulation zone is established:

[0100]

[0101] Based on the current dynamic reserves used in the unfractured zone, the following material balance model for the peripheral unfractured zone is established:

[0102]

[0103] in,

[0104]

[0105] In the formula, p1 is the current average formation pressure in the fracturing zone (MPa); p2 is the current average formation pressure in the surrounding unfracturing zone (MPa); p i The original formation pressure is given in MPa; c f ρ is the pore compressibility coefficient of shale, in MPa -1 S gi G1 represents the initial gas saturation, in fractions; G2 represents the dynamic reserves used in the current time step of the fracturing zone; G3 represents the dynamic reserves used in the current time step of the unfracturing zone; p represents the current formation pressure, in MPa. sc Standard pressure, 0.101 MPa; z * Z(p) is the deviation coefficient for corrected formation pressure p; Z is the deviation coefficient for natural gas. sc The deviation coefficient for natural gas under standard conditions is approximately 1; T is the temperature of the shale gas reservoir, in K; T sc Temperature under standard conditions, K; Φ is total porosity, fraction; ρ b The density of shale is t / m³. 3 V L The Langmuir isothermal adsorption volume of shale gas is given in m. 3 / t;P L The Langmuir isothermal adsorption pressure for shale gas is (MPa); c w The formation water compressibility coefficient is given in MPa. -1 ;s wiThe compressibility coefficient of bound water is given in MPa. -1 .

[0106] Next, the shale gas well productivity coefficient is calculated in step S400 based on the pressure propagation distance of the fracturing zone and the basic data.

[0107] In an optional embodiment, the shale gas well productivity coefficient is calculated using the following formula:

[0108]

[0109] In the formula, WIG is the natural gas production coefficient of the fractured horizontal well; K1(p) represents the permeability of the fractured zone, K1 is a function of pressure p (stress sensitive), h represents the shale reservoir thickness; uppercase T represents temperature, K; S t It represents the total skin coefficient; it is mainly composed of the streamline convergence skin coefficient and the limited conductivity skin coefficient.

[0110] On the other hand, the crossflow coefficient from the outer zone to the SRV zone of the fractured horizontal well is calculated based on the distance of the pressure drop funnel in the fracturing zone to the outer untreated zone, combined with basic data.

[0111]

[0112] in, WI g,12 The crossflow coefficient from the outer zone to the SRV zone of the fracturing horizontal well. K1 represents the combined penetration rate of the inner and outer zones, and K2 represents the penetration rate of the outer zone.

[0113] Based on the above embodiments, the current mean formation pressure in the SRV zone and the surrounding unfractured and modified zone is a parameter that needs to be iteratively solved for each time step. During the initial solution, this parameter is initialized to the formation pressure of the previous time step. If the previous time step t = 0, it is initialized to the original formation pressure.

[0114] At each iteration step, the formation pressure for the next iteration step is determined according to the Newton-Raphson iteration method.

[0115] Based on this, the operation is carried out according to the logic of step S500. Based on the iterative solution results of the average formation pressure of the shale gas reservoir material balance model in the fracturing and unfracturing zones, the production data of the current iteration step is calculated by combining the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the fracturing horizontal well in the outer zone, and then the cumulative production data is calculated.

[0116] Among them, the average formation pressure of each zone in the current time step is solved iteratively based on the material balance model of the fracturing zone and the surrounding unfracturing zone of the shale gas reservoir.

[0117] By coupling and iterating the material balance models of the fracturing zone and the surrounding unfracturing zone of the shale gas fracturing horizontal well, the average formation pressure of each zone at the current time step is solved.

[0118] In practical applications, based on the initial average formation pressure, the corresponding fracturing zone material balance iterative model is formed based on the fracturing zone material balance model of formula (6), as shown in formula (11):

[0119]

[0120] Based on the average formation pressure p1 of the fracturing zone in the current time step and the current iteration step, calculate Z. * (p1);

[0121] Based on the bottom-hole flowing pressure and average formation pressure p1, the current gas production index (production coefficient) of the fracturing area is calculated according to equation (9), the gas production of the gas well is calculated according to equation (13), and the cumulative gas production is calculated according to equation (15).

[0122] The cumulative crossflow production in equation (16) requires first iteratively solving the average formation pressure p2 of the current unmodified outer perimeter area, and iterating according to the following.

[0123] Given the current average formation pressure p1 in the fracturing zone, the current average formation pressure p2 can be solved iteratively using a mass balance model of the surrounding untreated zone. The iterative mass balance model is as follows:

[0124]

[0125] Calculate Z*(p2) based on the average formation pressure p2 of the current iteration; calculate the outer pressure propagation radius according to equation (2); if the pressure propagation radius is greater than 0, calculate the crossflow coefficient between the inner and outer zones according to equation (10), and calculate the crossflow production q according to equation (14). 12 The cumulative crossflow output is calculated according to equation (16), and the material balance residual is calculated according to equation (12).

[0126] Equation (12) is solved iteratively according to Newton's iteration method until the residual rsd is less than the given value. For example, the iteration convergence judgment condition is set to 1e-4. When the fitting error is less than this value, the iteration is terminated.

[0127] In the process of calculating the average formation pressure in the inner and outer zones, the formation pressure p2 in the outer unmodified zone is solved iteratively through the above operation, and then the residual of the material balance model in the inner zone is solved according to the Newton iteration method based on formula (11).

[0128] The mean formation pressures p1 and p2 in the inner and outer zones at the current time step can be finally solved by using a coupled iterative method based on a dual-zone material balance model.

[0129] This allows us to calculate the current gas production and cumulative gas production of the gas well, as well as the outflow production from the unrenovated area to the renovated area and the cumulative outflow production.

[0130] In an optional embodiment, the gas production of the gas well in the current iteration step and the gas flow production from the unmodified area to the SRV area are calculated according to the production capacity model and the crossflow model, respectively, and then the gas production of the gas well and the cumulative crossflow production are determined according to the time step.

[0131] Based on the production capacity coefficient, the current gas production of the step gas well is:

[0132] q1 = WI g ×(ψ1-ψ wf (13)

[0133] Based on the crossflow coefficient, the crossflow rate from the unmodified outer zone to the fracturing modified zone in the current iteration step is:

[0134] q 12 =WI g,12 ×(ψ2-ψ1) (14)

[0135] In the formula, q1 represents the gas production of the gas well in the current iteration step, and q 12 ψ1 represents the flow rate from the untreated zone to the fracturing zone in the current iteration step, and ψ1 represents the pseudo-pressure corresponding to the average formation pressure in the fracturing zone in the current time step, in MPa. 2 / cp; ψ2 is the pseudo-pressure corresponding to the average formation pressure in the unfractured outer zone at the current time step, in MPa 2 / cp. Ψ wf The pseudo-pressure corresponding to the bottom hole flowing pressure, in MPa 2 / cp.

[0136] The cumulative gas production of the gas well and the cumulative flow from the untreated area to the fracturing area are calculated based on the current time step.

[0137] G p =G p (t n-1 )+q1×△t (15)

[0138]

[0139] In the formula, G p G represents the cumulative gas production of a gas well. p12 This represents the cumulative flow from the untreated area to the fracturing area, where q1 is the gas production of the current iteration well, and q 12 Δt represents the flow rate from the unmodified zone to the fracturing zone in the current iteration step, where Δt represents the time step and n represents the iteration step.

[0140] Based on the average formation pressure in the inner zone obtained through iterative calculation at the current time step, the gas production of the gas well is calculated according to equation (13), and then the cumulative gas production is calculated according to equation (15); on the other hand, based on the average formation pressure in the outer zone obtained through iterative calculation at the current time step, the crossflow production q is calculated according to equation (14). 12 The cumulative cross-flow output is calculated according to equation (16).

[0141] Based on the above logic, after the calculation is completed, the time step is automatically switched to the next time step to determine whether the calculation is finished. If the calculation is finished, the calculation result is returned and output; otherwise, the process returns to step 200 and repeats.

[0142] The present invention will be further described below with reference to specific embodiments. The scope of the present invention is not limited to the embodiments, but is defined in the claims.

[0143] The following example uses the C-HF well (a marine shale gas fracturing horizontal well) in the Longmaxi Formation of the Sichuan Basin to illustrate the present invention's method for evaluating the dual-zone composite material balance production capacity of fracturing horizontal wells.

[0144] The basic geological and fracturing parameters of the well are shown in Table 1 below:

[0145] Table 1 Basic Parameters of Jiaoye C-HF Well

[0146] Parameter name Parameter value Parameter name Parameter value Initial formation pressure (MPa) 52.6 Inner diameter of the sleeve (mm) 115.5 Gas reservoir temperature (°C) 90 Oil pipe outer diameter (mm) 72 Gas reservoir thickness (m) 38 Oil pipe inner diameter (mm) 62 Total porosity (%) 4.81 Tubing depth (m) 2960 <![CDATA[Pore compressibility coefficient (MPa -1 )]]> 1.82e-3 Length of horizontal section of horizontal well (m) 1220 Natural gas relative density 0.567 Number of fracturing clusters 41 <![CDATA[Lange volume (m 3 / t)]]> 2.5 <![CDATA[Half-length X of the main crack f (m)]]> / Langevin pressure (MPa) 6 Main fracture conductivity (mD.m) / <![CDATA[Shale density (t / m 3 )]]> 2.55 Well spacing (m) 300 Reservoir vertical depth (m) 3163 Wellbore radius (m) 0.06

[0147] This invention determines parameters through historical data fitting and then predicts production capacity. Taking the Jiaoye C-HF well as an example, production capacity is predicted based on historical fitting parameters. The historical fitting parameters for the Jiaoye C-HF well are shown in Table 2 below:

[0148] Table 2 Historical Fitting Parameters of Jiaoye C-HF Well

[0149] Fitting parameter names Fitted parameter values Fitting parameter names Fitted parameter values Initial formation pressure (MPa) 52.6 SRV zone permeability (mD) 3.33e-4 Crack half-length Xf(m) 35 Permeability of the outer matrix (mD) 5e-5 Crack conductivity (mD.m) 0.45

[0150] The production curve example for the Jiaoye C-HF well in this implementation case is shown in the figure below. Figure 5 As shown in the figure; the production history fitting example diagram of the Jiaoye C-HF well in this implementation case is as follows. Figure 6 As shown in the figure; an example diagram of the material balance production capacity prediction for the Jiaoye C-HF well in this embodiment is shown in the figure. Figure 7 As shown.

[0151] For the foregoing method embodiments, in order to simplify the description, they are all described as a series of actions. However, those skilled in the art should understand that the present invention is not limited to the described order of actions, because according to the present invention, some steps can be performed in other orders or simultaneously. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions and modules involved are not necessarily essential to the present invention.

[0152] It should be noted that, in other embodiments of the present invention, the method can also combine one or more of the above embodiments to obtain a new method for evaluating the reserves of shale gas fractured horizontal wells based on dual-zone composite material balance, so as to achieve accurate and efficient prediction and evaluation of the recoverable reserves of shale gas fractured horizontal wells.

[0153] Example 2

[0154] It should be noted that, based on the methods in any one or more embodiments of the present invention described above, the present invention also provides a storage medium storing program code that can implement the methods described in any one or more embodiments. When the program code is executed by the operating system, it can implement the shale gas fracturing horizontal well reserve evaluation method based on dual-zone composite material balance as described above.

[0155] Example 3

[0156] The methods described in the above-disclosed embodiments of the present invention are detailed. These methods can be implemented using various devices or systems. Therefore, based on other aspects of the methods described in any one or more of the above embodiments, the present invention also provides a shale gas fracturing horizontal well reserve evaluation system based on dual-zone composite material balance. This system is used to execute the shale gas fracturing horizontal well reserve evaluation method based on dual-zone composite material balance described in any one or more of the above embodiments. Specific embodiments are given below for detailed description.

[0157] Specifically, the recoverable reserves evaluation system for shale gas fracturing horizontal wells based on dual-zone composite material balance provided in this embodiment of the invention includes:

[0158] The basic data preparation module is configured to prepare basic data for shale gas fracturing horizontal wells, including basic geological parameters, adsorption and desorption parameters, shale gas parameters, and multi-stage fracturing parameters.

[0159] The propagation distance analysis module is configured to set the calculation time step and calculate the pressure propagation distance of the fracturing modified zone and the distance of the pressure drop funnel propagating to the surrounding unmodified zone based on the time step information and the pressure propagation mechanism.

[0160] The material mechanism model construction module is configured to calculate the dynamic reserves mobilized in the fracturing zone and the outer zone based on the pressure propagation distance, and then establish material balance models of shale gas reservoirs in the fracturing zone and the surrounding unfracturing zone, respectively.

[0161] The production capacity correlation coefficient calculation module is configured to calculate the production capacity coefficient of shale gas wells and the SRV zone crossflow coefficient of external fractured horizontal wells by combining basic data.

[0162] The dual-zone coupled model solution module is configured to calculate the average formation pressure results of the shale gas reservoir dual-zone coupled material balance model based on the fracturing zone and the surrounding unfracturing zone. It then combines the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the fracturing horizontal well in the outer zone to calculate the production data of the current iteration step, and then calculates the cumulative production data.

[0163] Furthermore, in one embodiment, the basic data preparation module sets basic geological parameters including: initial formation pressure, relative density of natural gas, gas reservoir temperature, reservoir thickness, total porosity, gas saturation, water saturation, and shale porosity compressibility.

[0164] Adsorption and desorption parameters include Langmuir pressure, Langmuir volume, and shale density;

[0165] Multi-stage fracturing parameters include horizontal well length, number of fracturing fractures, half-length of the main fracture, and conductivity of the main fracture.

[0166] The shale gas parameters are calculated using the shale gas PVT parameters based on the relative density of natural gas using the corresponding property model.

[0167] In an optional embodiment, the propagation distance analysis module calculates the pressure propagation distance in the fracturing zone using the following formula:

[0168]

[0169] In the formula, Y inv1 K1 represents the pressure propagation distance in the fracturing zone, t represents time, φ represents reservoir porosity, μ represents natural gas viscosity, and c represents the permeability of the fracturing zone in the horizontal well. t L represents the overall compressibility coefficient of shale; the subscript i indicates that the parameter value is taken under the initial state. s Indicates the spacing between adjacent cracks;

[0170] The distance the pressure drop funnel from the fracturing-treated zone propagates to the surrounding untreated zone is calculated using the following formula:

[0171]

[0172]

[0173] In the formula, Y inv2 K1 represents the distance the pressure drop funnel from the fracturing zone propagates to the surrounding untreated zone; K2 represents the permeability of the SRV zone of the fracturing horizontal well; t represents time. elf c is the pressure disturbance time between adjacent main fractures; ti μ is the overall compressibility coefficient under initial pressure. i Y represents the viscosity of natural gas at the initial pressure. eLe is the model width; Le is the length of the horizontal section of the horizontal well; n f This represents the number of cracks.

[0174] Furthermore, in one embodiment, the material mechanism model construction module is configured to: calculate the dynamic reserves used in the fracturing zone at the current time step and the dynamic reserves used in the unfracturing zone at the current time step using the volume method and the volumetric method, respectively, based on the pressure propagation distance and the distance propagated from the pressure drop funnel of the fracturing zone to the surrounding unfracturing zone.

[0175] In a preferred embodiment, the material mechanism modeling module calculates the dynamic reserves G1 utilized in the fracturing zone at the current time step using the following formula:

[0176]

[0177] The dynamic reserves G2 currently used in the unfractured zone are calculated using the following formula:

[0178]

[0179] In the formula, h is the thickness of the shale reservoir, in meters; X f B represents the half-length of a fracture in a horizontal shale gas fracturing well, in meters. gi L is the natural gas volume factor under the initial formation pressure; s The distance between adjacent fractures in a shale gas fracturing horizontal well is in meters (m).

[0180] Optionally, in one embodiment, the material mechanism model building module establishes the following material balance model for the fracturing zone:

[0181]

[0182] The following material balance model for the unfractured outer perimeter zone is established:

[0183]

[0184] in,

[0185]

[0186] In the formula, p1 is the current average formation pressure in the fracturing zone; p2 is the current average formation pressure in the surrounding unfracturing zone; p i The original formation pressures a and c are... f S is the pore compressibility coefficient of shale; gi G1 represents the original gas saturation; G2 represents the dynamic reserves used in the current time step of the fracturing zone; G3 represents the dynamic reserves used in the current time step of the unfracturing zone; and p represents the current formation pressure. sc Standard pressure; z *Z(p) is the deviation coefficient for corrected formation pressure p; Z is the deviation coefficient for natural gas. sc T is the deviation coefficient of natural gas under standard conditions; T is the temperature of the shale gas reservoir; T sc Temperature under standard conditions; Φ is total porosity; ρ b V is the density of shale; L Langmuir isothermal adsorption volume for shale gas; P L Langmuir isothermal adsorption Langmuir pressure for shale gas; c w s is the formation water compressibility coefficient; wi is the compressibility coefficient of bound water.

[0187] Specifically, in a preferred embodiment, the production capacity correlation coefficient calculation module calculates the shale gas well production capacity coefficient using the following formula:

[0188]

[0189] In the formula, WIg is the natural gas production coefficient of the fractured horizontal well; K1(p) represents the permeability of the fractured zone, K1 is a function of pressure p; h represents the shale reservoir thickness; uppercase T represents temperature; S t This represents the total skin coefficient.

[0190] Optionally, in one embodiment, the production capacity correlation coefficient calculation module calculates the outward flow coefficient from the fracturing zone to the untreated zone based on the distance the pressure drop funnel in the fracturing zone propagates to the surrounding untreated zone, combined with basic data, using the following formula:

[0191]

[0192] In the formula, WI g,12 The crossflow coefficient from the outer zone to the SRV zone of the fracturing horizontal well. To harmonize penetration rates between internal and external zones, K2 represents the penetration rate in the outer zone.

[0193] It should be noted that the units described in the embodiments of this disclosure can be implemented in software or hardware. Furthermore, the names of the units do not necessarily limit the specific unit itself.

[0194] In the shale gas fracturing horizontal well recoverable reserves evaluation system based on dual-zone composite material balance provided by the embodiments of the present invention, each module or unit structure can operate independently or in combination according to the actual calculation model establishment requirements and iterative solution requirements to achieve the corresponding technical effects.

[0195] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0196] The phrase "an embodiment" in the specification means that a specific feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0197] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for evaluating the recoverable reserves of shale gas fractured horizontal wells based on dual-zone composite material balance, characterized in that, The method includes: Step S100: Prepare basic data for shale gas fracturing horizontal wells, including basic geological parameters, adsorption and desorption parameters, shale gas parameters, and multi-stage fracturing parameters; Step S200: Set the calculation time step, and calculate the pressure propagation distance of the fracturing zone and the distance of the pressure drop funnel from the outer unmodified zone according to the time step information and the pressure propagation mechanism; Step S300: Calculate the dynamic reserves mobilized in the fracturing zone and the outer zone based on the pressure propagation distance, and then establish shale gas reservoir material balance models for the fracturing zone and the surrounding unfracturing zone respectively; Step S400: Calculate the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the external fractured horizontal well based on the basic data; Step S500: Based on the average formation pressure results obtained by iteratively solving the dual-zone coupled material balance model of the shale gas reservoir in the fracturing zone and the surrounding unfracturing zone, the production data of the current iteration step is calculated by combining the shale gas well productivity coefficient and the SRV zone crossflow coefficient of the fracturing horizontal well in the outer zone, and then the cumulative production data is calculated.

2. The method according to claim 1, characterized in that, In step S100, the basic geological parameters include: initial formation pressure, relative density of natural gas, gas reservoir temperature, reservoir thickness, total porosity, gas saturation, water saturation, and shale porosity compressibility. Adsorption and desorption parameters include Langmuir pressure, Langmuir volume, and shale density; Multi-stage fracturing parameters include horizontal well length, number of fracturing fractures, half-length of the main fracture, and conductivity of the main fracture. The shale gas parameters are calculated using the shale gas PVT parameters based on the relative density of natural gas using the corresponding property model.

3. The method according to claim 1, characterized in that, In step S200, the pressure propagation distance in the fracturing zone is calculated using the following formulas: In the formula, Y inv1 K1 represents the pressure propagation distance in the fracturing zone, t represents time, φ represents reservoir porosity, μ represents natural gas viscosity, and c represents the permeability of the fracturing zone in the horizontal well. t L represents the overall compressibility coefficient of shale; the subscript i indicates that the parameter value is taken under the initial state. s This indicates the spacing between adjacent cracks.

4. The method according to claim 1, characterized in that, The distance from the pressure drop funnel in the fracturing zone to the surrounding untreated zone is calculated using the following formula: In the formula, Y inv2 K1 represents the distance the pressure drop funnel from the fracturing zone propagates to the surrounding untreated zone; K2 represents the permeability of the SRV zone of the fracturing horizontal well; t represents time. elf c is the pressure disturbance time between adjacent main fractures; ti μ is the overall compressibility coefficient under initial pressure. i Y represents the viscosity of natural gas at the initial pressure. e Le is the model width; Le is the length of the horizontal section of the horizontal well; n f This represents the number of cracks.

5. The method according to claim 1, characterized in that, In step S300, based on the pressure propagation distance and the distance the pressure drop funnel in the fracturing zone propagates to the surrounding untreated zone, the dynamic reserves used in the fracturing zone at the current time step and the dynamic reserves used in the untreated zone at the current time step are calculated using the volume method and the volumetric method, respectively.

6. The method according to claim 5, characterized in that, In step S300, the dynamic reserves G1 used in the current time step of the fracturing stimulation zone are calculated by the following formula: The dynamic reserves G2 currently used in the unfractured zone are calculated using the following formula: In the formula, h is the thickness of the shale reservoir, in meters; X f B represents the half-length of a fracture in a horizontal shale gas fracturing well, in meters. gi L is the natural gas volume factor under the initial formation pressure; s The distance between adjacent fractures in a shale gas fracturing horizontal well is in meters (m).

7. The method according to claim 1, characterized in that, In step S300, the following material balance model for the fracturing zone is established: The following material balance model for the unfractured outer perimeter zone is established: in, In the formula, p1 is the current average formation pressure in the fracturing zone; p2 is the current average formation pressure in the surrounding unfracturing zone; p i The original formation pressures a and c are... f S is the pore compressibility coefficient of shale; gi G1 represents the original gas saturation; G2 represents the dynamic reserves used in the current time step of the fracturing zone; G3 represents the dynamic reserves used in the current time step of the unfracturing zone; and p represents the current formation pressure. sc Standard pressure; z * Z(p) is the deviation coefficient for corrected formation pressure p; Z is the deviation coefficient for natural gas. sc T is the deviation coefficient of natural gas under standard conditions; T is the temperature of the shale gas reservoir; T sc Temperature under standard conditions; Φ is total porosity; ρ b V is the density of shale; L Langmuir isothermal adsorption volume for shale gas; P L Langmuir isothermal adsorption Langmuir pressure for shale gas; c w s is the formation water compressibility coefficient; wi is the compressibility coefficient of bound water.

8. The method according to claim 1, characterized in that, In step S400, the shale gas well productivity coefficient is calculated using the following formula: In the formula, WI g K1(p) represents the natural gas production coefficient of the fractured horizontal well; K1(p) represents the permeability of the fractured zone, which is a function of pressure p; h represents the shale reservoir thickness; uppercase T represents temperature; S t This represents the total skin coefficient.

9. The method according to claim 1, characterized in that, In step S400, based on the distance of the pressure drop funnel from the fracturing zone to the surrounding untreated zone and combined with basic data, the flow coefficient from the outer zone to the SRV zone of the fracturing horizontal well is calculated using the following formula: In the formula, WI g,12 The crossflow coefficient from the outer zone to the SRV zone of the fracturing horizontal well. To harmonize penetration rates between internal and external zones, K2 represents the penetration rate in the outer zone.

10. A storage medium, characterized in that, The storage medium stores program code capable of implementing the method as described in any one of claims 1 to 9.

11. A system for evaluating the recoverable reserves of shale gas fractured horizontal wells based on dual-zone composite material balance, characterized in that, The system performs the method as described in any one of claims 1 to 9.

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