Oil shale formation temperature field simulation method and system for fluid injection heating exploitation

Abstract

The invention provides an oil shale formation temperature field simulation method and system for fluid injection heating mining, a storage area is divided into a plurality of unit mining spaces according to geologic feature data of the storage area to be mined, a mass conservation operation model corresponding to fluid injection in-situ mining is constructed for each unit mining space based on the principle of mass conservation, and the temperature field of the oil shale formation is simulated. According to the principle that high-temperature fluid carries heat to conduct heat transfer and exchange with a rock mass system in a conduction and convection mode and the influence on a temperature field in a rock mass, an energy operation model corresponding to fluid injection in-situ mining is built; preset initial parameters are introduced, the mass conservation operation model and the energy operation model are solved based on the discrete process, initial mass field data and energy field data are calculated, and then temperature field data of subsequent time are calculated in combination with a Newton iteration method. According to the scheme, the limitation of low precision of existing temperature field simulation is overcome, and rigorous and accurate temperature field space-time distribution of the oil shale under fluid injection heating is obtained.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum geological development, and in particular to a method and system for simulating the temperature field of an oil shale formation during fluid injection heating exploitation. Background Art

[0002] Currently, there are two main methods for oil shale development: surface retorting, where shale is mined underground and then heated and retorted aboveground; and in-situ extraction, where shale oil and gas are directly brought to the surface through underground heating and retorting. Surface industrial retorting typically involves crushing and screening the mined oil shale before retorting it in an oil shale retorting furnace to produce shale oil. This traditional production model, characterized by grinding and combustion, has disadvantages such as low efficiency, high pollution, and high cost. Exhaust gases contain toxic gases and inhalable dust, polluting the surrounding environment. Furthermore, industrial retorting furnaces generate a significant amount of waste residue, which is difficult to recycle. Therefore, it is crucial to develop low-pollution, high-efficiency methods for oil shale extraction, adhere to and strengthen energy conservation efforts throughout the entire process and across all areas, continuously reduce carbon dioxide emissions at the source, and promote a comprehensive green transition in economic and social development. In-situ extraction, due to its advantages of low cost, small footprint, low pollution, and ability to mine deep oil shale, has become a key focus of oil shale mining research. Numerous research institutions and energy companies have conducted related research, including Shell's ICP electric heating technology, which has successfully undergone field trials. Therefore, underground in-situ mining technology of oil shale has become the main trend of future oil shale development.

[0003] The numerical simulation analysis of fluid heating in underground in-situ mining technology is more complex than that of electric heating, and corresponding research exists in the existing technology. For example, Wang Jian studied the method of using horizontal fractures for steam heating after fracturing the rock formation. Taking into account the rock heat conduction equation and the convective heat transfer of water vapor, he simulated the changes in the two-dimensional rock temperature field and explored the influence of fracture location on the heating effect. Pei Baolin ignored the heat transfer effect of cracking gas during fluid heating. Using the heat transfer equations of fluid and rock formation and the deformation equation of rock under pore pressure, and considering the changes in rock formation porosity, he conducted a numerical simulation of the temperature field of the convective heating method of oil shale with oil production wells and gas injection wells, and compared the effects of gas injection temperature and pressure on mining efficiency. On this basis, Kang Zhiqin and Li Kai considered the heat transfer of pyrolysis gas and the changes in the physical properties of shale and fluid with temperature, added the phase change factors of water and water vapor, and treated water and water vapor as a homogeneous mixture to simplify the two-phase change of water. Using equations for fluid heat transfer and rock temperature fields, as well as equations for rock deformation caused by thermal stress, the temperature, seepage, and rock stress fields of three-dimensional oil shale containing production wells and heat injection wells under thermal-solid-fluid coupling were simulated. While this technique integrates the principles of pyrolysis operations for downhole in-situ mining to comprehensively analyze the relevant influencing factors, the factors considered in the simulation calculations have significant limitations. It ignores the difference in thermal conductivity between rock and fluids, and fails to account for temperature variations within the fluid. This makes it unsuitable for in-situ mining processes involving fluid injection heating. Furthermore, the incompleteness of the parameters can lead to deviations between the calculated results and actual conditions, and the accuracy cannot meet the data requirements of actual in-situ mining operations.

[0004] The information disclosed in the background technology section of the present invention is only intended to deepen the understanding of the general background technology of the present invention, and should not be regarded as an admission or any form of suggestion that the information constitutes the prior art known to those skilled in the art. Summary of the Invention

[0005] To address the above-mentioned issues, the present invention provides a method for simulating the temperature field of oil shale formations during fluid injection heating. Based on the mass conservation equation and the energy conservation equation, the method characterizes the spatiotemporal distribution of the oil shale temperature field, accurately fits the heating process of the oil shale, and can clearly and effectively reflect the temperature variation process of the oil shale heating process with simulation results, providing data guidance for in-situ oil shale mining. In one embodiment, the method comprises:

[0006] The simulation unit setting step is to divide the reservoir into a number of unit mining spaces according to the geological characteristic data of the reservoir to be mined, and it is appropriate to set up a group of operating wells in each unit mining space, including a heating well and a production well;

[0007] The mass calculation model analysis steps are as follows: Based on the mass conservation principle, a mass conservation calculation model corresponding to in-situ production of injection fluid is constructed for each unit production space, so as to use the model to analyze the mass field data corresponding to different times during the production implementation process;

[0008] Energy calculation model analysis steps: Based on the principle that high-temperature fluid carries heat and transfers heat with the rock system through conduction and convection, and its impact on the temperature field within the rock mass, an energy calculation model corresponding to fluid injection in-situ mining is constructed. This model is used to analyze the energy field data corresponding to different times during the mining implementation process;

[0009] The temperature field data calculation step introduces preset initial parameters to solve the mass conservation calculation model and energy calculation model based on a discrete process to calculate the initial mass field data and energy field data, and then combines the Newton iteration method to calculate the mass field data and energy field data at subsequent times to characterize the temperature field state of the unit mining space.

[0010] Furthermore, in one embodiment, the method also includes conducting an in-situ fluid injection production simulation experiment based on a reservoir sample or reservoir model that is consistent with the geological characteristic data of the reservoir area to be mined according to preset initial parameters, and comparing the results of the simulation experiment with the calculation results obtained using the operation model of this application at the corresponding time for verification.

[0011] Optionally, in one embodiment, in the mass calculation model analysis step, a mass conservation calculation model as shown below is constructed:

[0012]

[0013] Among them, F i represents the mass partial derivative operation based on component i, φ represents the formation porosity, S j represents the j-phase saturation, q j represents the j-phase flow rate, the subscript i represents HC gas, j represents gas, φ is the porosity, ξ j is the molar density of phase j, X ij represents the mole fraction of component i in phase j, u j represents the j-phase velocity, Indicates the flow rate of gas injection.

[0014] Furthermore, in one embodiment, in the energy calculation model analysis step, based on the decomposition of kerogen by the fluid when heated, and combined with the influence of the kerogen decomposition reaction on the rock pores, an energy calculation model corresponding to the in-situ mining of the injected fluid is constructed.

[0015] Preferably, in one embodiment, in the energy calculation model analysis step, an energy calculation model corresponding to in-situ production of injection fluid is constructed according to the following logic:

[0016]

[0017] Among them, Fe represents the energy partial derivative operation, ρ j represents the density of phase j, T represents the temperature, and q H represents the heat flow rate of the injection well, q j Indicates the j-phase flow rate, j-phase represents the gas phase, U j is the internal energy of phase j, ρ s is the density of kerogen, c s is the heat capacity of kerogen, k is the thermal conductivity, H j is the enthalpy of the gas phase.

[0018] In an optional embodiment, in the temperature field data calculation step, the initial parameters set include: initial pressure, initial temperature, injection gas temperature, and production well BHP and heat capacity.

[0019] Preferably, in one embodiment, the temperature field data calculation step includes the following operations:

[0020] The initial and boundary conditions to be solved are taken as the initial time t n The mass and temperature field distribution inside the reservoir rock formation, where only the time differential term is retained by differentiating the spatial coordinate grid when solving the differential equation, making it a time-continuous ordinary differential equation;

[0021] Calculate the next moment, t, by the Newton iteration method n+1 The mass field and temperature field distribution;

[0022] Judge the time situation. If the time does not meet the requirements, repeat the above steps to calculate t n+2 The temperature field data at each moment is obtained through cyclic operation, and the time domain temperature field change data during the in-situ mining process of the reservoir is obtained.

[0023] As a further improvement of the present invention, in one embodiment, the method further comprises: generating a corresponding isotherm visual graph based on the temporal temperature field variation data during the in-situ mining process of the reservoir area;

[0024] Set the observation time period according to observation requirements and mark the corresponding isotherm part to facilitate users to selectively view and analyze.

[0025] Based on other aspects of the method described in any one or more of the above embodiments, the present invention further provides a storage medium storing program codes that can implement the method described in any one or more of the above embodiments.

[0026] Based on the application aspects of the method described in any one or more of the above embodiments, the present invention also provides a temperature field simulation system for oil shale formations produced by fluid injection heating, which executes the method described in any one or more of the above embodiments.

[0027] Compared with the closest prior art, the present invention also has the following beneficial effects:

[0028] The present invention provides a method and system for simulating the temperature field of oil shale formations using fluid injection heating. Based on the geological characteristics of the reservoir area to be mined, the reservoir is divided into several unit mining spaces. Based on the principle of mass conservation, a mass conservation computational model corresponding to in-situ fluid injection mining is constructed for each unit mining space. Based on the principle that high-temperature fluid carries heat and transfers heat with the rock system through conduction and convection, and its impact on the temperature field within the rock mass, an energy computational model corresponding to in-situ fluid injection mining is constructed. Preset initial parameters are then introduced to solve the mass conservation computational model and the energy computational model based on a discrete process to calculate initial mass and energy field data. The Newton iteration method is then used to calculate subsequent temperature field data. The computational model of the present invention considers the effects of heat conduction and convection carried by the high-temperature fluid on the temperature field distribution within the rock mass, as well as the effects of kerogen decomposition, to determine the spatiotemporal distribution of the oil shale temperature field under gas injection heating. This model utilizes basic operational data from the reservoir area to achieve accurate and reliable in-situ mining data simulation.

[0029] Other features and advantages of the present invention will be described in the following description, and in part will become apparent from the description, or will be understood by practicing the present invention. The purposes and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0031] Figure 1 This is a flow chart of a method for simulating the temperature field of an oil shale formation by fluid injection heating production according to an embodiment of the present invention;

[0032] Figure 2 This is an example diagram of a unit mining space of the method for simulating the temperature field of an oil shale formation by fluid injection heating mining provided by an embodiment of the present invention;

[0033] Figure 3 This is a detailed diagram of the calculation process of the method for simulating the temperature field of an oil shale formation by fluid injection heating mining provided in an embodiment of the present invention;

[0034] Figure 4It is a schematic diagram of the analysis results of the oil shale temperature field under different injection rates in the oil shale formation temperature field simulation method for fluid injection heating production provided by one embodiment of the present invention. DETAILED DESCRIPTION

[0035] The following will describe in detail the implementation methods of the present invention in conjunction with the accompanying drawings and embodiments, so that practitioners of the present invention can fully understand how the present invention applies technical means to solve technical problems and achieve the implementation process of technical effects, and can implement the present invention in accordance with the above implementation process. It should be noted that as long as no conflict exists, the various embodiments and various features of each embodiment in the present invention can be combined with each other, and the resulting technical solutions are all within the scope of protection of the present invention.

[0036] Although the flowcharts depict the operations as sequential processes, many of the operations can be performed in parallel, concurrently, or simultaneously. The order of the operations can be rearranged. A process can be terminated when its operations are completed, but can also have additional steps not included in the figures. A process can correspond to a method, function, procedure, subroutine, subprogram, etc.

[0037] The term "and / or" as used herein includes any and all combinations of one or more of the associated listed items. When an element is referred to as being "connected" or "coupled" to another element, it can be directly connected or coupled to the other element, or intervening elements may be present.

[0038] The terms used herein are intended only to describe specific embodiments and are not intended to limit exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms "a", "an", "an item" used herein are also intended to include the plural. It should also be understood that the terms "comprise" and / or "include" used herein specify the presence of stated features, integers, steps, operations, units and / or components, and do not preclude the presence or addition of one or more other features, integers, steps, operations, units, components and / or combinations thereof.

[0039] Currently, there are two main methods for oil shale development: surface retorting, where shale is mined underground and then heated and retorted aboveground; and in-situ extraction, where shale oil and gas are directly brought to the surface through underground heating and retorting. Surface industrial retorting typically involves crushing and screening the mined oil shale before retorting it in an oil shale retorting furnace to produce shale oil. This traditional production model, characterized by grinding and combustion, has disadvantages such as low efficiency, high pollution, and high cost. Exhaust gases contain toxic gases and inhalable dust, polluting the surrounding environment. Furthermore, industrial retorting furnaces generate a significant amount of waste residue, which is difficult to recycle. Therefore, it is crucial to develop low-pollution, high-efficiency methods for oil shale extraction, adhere to and strengthen energy conservation efforts throughout the entire process and across all areas, continuously reduce carbon dioxide emissions at the source, and promote a comprehensive green transition in economic and social development. In-situ extraction, due to its advantages of low cost, small footprint, low pollution, and ability to mine deep oil shale, has become a key focus of oil shale mining research. Numerous research institutions and energy companies have conducted related research, including Shell's ICP electric heating technology, which has successfully undergone field trials. Therefore, underground in-situ mining technology of oil shale has become the main trend of future oil shale development.

[0040] The numerical simulation analysis of fluid heating in underground in-situ mining technology is more complex than that of electric heating, and corresponding research exists in the existing technology. For example, Wang Jian studied the method of using horizontal fractures for steam heating after fracturing the rock formation. Taking into account the rock heat conduction equation and the convective heat transfer of water vapor, he simulated the changes in the two-dimensional rock temperature field and explored the influence of fracture location on the heating effect. Pei Baolin ignored the heat transfer effect of cracking gas during fluid heating. Using the heat transfer equations of fluid and rock formation and the deformation equation of rock under pore pressure, and considering the changes in rock formation porosity, he conducted a numerical simulation of the temperature field of the convective heating method of oil shale with oil production wells and gas injection wells, and compared the effects of gas injection temperature and pressure on mining efficiency. On this basis, Kang Zhiqin and Li Kai considered the heat transfer of pyrolysis gas and the changes in the physical properties of shale and fluid with temperature, added the phase change factors of water and water vapor, and treated water and water vapor as a homogeneous mixture to simplify the two-phase change of water. Using equations for fluid heat transfer and rock temperature fields, as well as equations for rock deformation caused by thermal stress, researchers simulated the temperature, seepage, and rock stress field changes in three-dimensional oil shale containing production wells and heat injection wells under thermal-solid-fluid coupling. Zhao Limei used a similar approach, treating water vapor, coal gas, and shale oil and gas as a homogeneous mixture and incorporating the exothermic heat of shale pyrolysis chemical reactions. She numerically simulated the temperature, seepage, and stress field changes in oil shale and coal seams under co-heating conditions and designed a co-gasification furnace process for in-situ mining of coal and oil shale using co-heating. Youtsos et al. introduced the five main chemical reactions of oil shale pyrolysis in their numerical simulation of CO2 injection mining of oil shale, taking into account the heavy oil, light oil, coke, and gas (treated as a mixture) produced by kerogen and its decomposition.

[0041] Although the above technology combines the pyrolysis operation principle of underground in-situ mining to coordinate relevant influencing factors to realize the state analysis of the thermal field, there are obvious limitations in the factors considered in its simulation calculation process. It ignores the difference between the thermal conductivity of rocks and the heat transfer rate between fluids, and does not consider the temperature difference within the fluid. It is not suitable for mining processes that use fluid injection heating. In addition, the incomplete parameters will affect the deviation between the calculation results and the actual situation, and the accuracy cannot meet the data requirements of actual in-situ mining operations.

[0042] To solve the above problems, the present invention provides a method and system for simulating the temperature field of oil shale formations for fluid injection heating and mining, which simulates the temperature field numerical value of the fluid injection in-situ mining process of oil shale, and can reflect the spatiotemporal distribution characteristics of the oil shale temperature field with clear and effective simulation results, laying the foundation for the design of fluid heating well layout pattern, heating well temperature and well center distance, and can overcome the limitation of low accuracy of existing oil shale gas injection heating temperature field simulation. Compared with other heating methods, the fluid injection heating method has fast heat conduction and fast oil layer temperature increase, and can well fit the temperature results of the in-situ mining operation of oil shale.

[0043] Next, the detailed process of the method according to the embodiment of the present invention is described in detail based on the accompanying drawings. The steps shown in the flowcharts of the accompanying drawings can be executed in a computer system including, for example, a set of computer-executable instructions. Although the logical order of the steps is shown in the flowcharts, in some cases, the steps shown or described can be executed in a different order than here.

[0044] Example 1

[0045] Figure 1 The flow chart of the method for simulating the temperature field of oil shale formation by fluid injection heating mining provided in the first embodiment of the present invention is shown. Figure 1 It can be seen that the method includes the following steps.

[0046] The simulation unit setting step is to divide the reservoir into a number of unit mining spaces according to the geological characteristic data of the reservoir to be mined, and it is appropriate to set up a group of operating wells in each unit mining space, including a heating well and a production well;

[0047] The mass calculation model analysis steps are as follows: Based on the mass conservation principle, a mass conservation calculation model corresponding to in-situ production of injection fluid is constructed for each unit production space, so as to use the model to analyze the mass field data corresponding to different times during the production implementation process;

[0048] Energy calculation model analysis steps: Based on the principle that high-temperature fluid carries heat and transfers heat with the rock system through conduction and convection, and its impact on the temperature field within the rock mass, an energy calculation model corresponding to fluid injection in-situ mining is constructed. This model is used to analyze the energy field data corresponding to different times during the mining implementation process;

[0049] The temperature field data calculation step introduces preset initial parameters to solve the mass conservation calculation model and energy calculation model based on a discrete process to calculate the initial mass field data and energy field data, and then combines the Newton iteration method to calculate the mass field data and energy field data at subsequent times to characterize the temperature field state of the unit mining space.

[0050] Compared with other heating methods, the fluid injection heating method has fast heat conduction and the oil layer temperature rises quickly, but the types of parameters involved in the operation process are more complicated. According to experimental data, it is found that the heat conduction rate of rock is much faster than the heat transfer between fluids. The existing technology ignores the temperature difference within the fluid. Based on this, the fitting calculation process in the above embodiment of the present invention takes into account the phase change of the oil and gas phases and the changes in physical parameters such as porosity and permeability with temperature, establishes a group of flow field control equations, and combines Darcy's law and the gas state equation to perform numerical simulations of the temperature field, pyrolysis rate and gas production of oil shale pyrolysis, overcoming the limitation of low accuracy of existing oil shale gas injection heating temperature field simulation.

[0051] In addition, the technical solution of the present invention is different from the existing technology based on the thermal component model algorithm widely used in fugacity and commercial numerical simulation software. Instead, it constructs a corresponding thermal component model based on the simpler phase equilibrium ratio K value, and develops a smoothed thermal component model algorithm that does not require phase change discrimination during the calculation process, theoretically making the simulation calculation easier to converge. It is also different from the method of constructing a mathematical model for in-situ oil shale mining based on the coupling of multiphase flow and temperature field. Instead, it is based on the thermal component model, which can more accurately predict the production of various organic and inorganic components during the in-situ oil shale mining process. Different from the method of using finite element commercial numerical simulation software to simulate oil shale development, the solution of the present invention is based on the finite volume method to meet the local conservation of matter, and uses a thermal component model, which has higher calculation accuracy.

[0052] Preferably, in one embodiment, basic information of unit mining space is constructed according to the following logic: taking the oil shale in a cubic area of ​​10m*10m*20m as an example, Figure 2 As shown, production is carried out through in-situ mining, using HC gas heating at an injection rate of 50 tons per day. Consider a single heater well and one production well. The heater and production wells are located at opposite corners of a square. Adiabatic boundary conditions are primarily used for boundary selection, ensuring no flow of components across the boundaries.

[0053] After dividing the reservoir into several unit mining spaces based on the geological characteristics of the reservoir to be mined, a mass conservation calculation model corresponding to in-situ mining of the injection fluid is constructed for each unit mining space based on the principle of mass conservation through the mass calculation model analysis step. This model is used to analyze the mass field data corresponding to different times during the mining implementation process.

[0054] In actual application, in one embodiment, the following basic model assumptions are set:

[0055] In order to make the established mathematical model reflect the physical essence without making the problem too complicated and difficult to solve, taking into account the chemical changes of various components, based on the above analysis, the mass conservation model and energy conservation model are used for research and reasonable assumptions are given.

[0056] Assume that oil shale is a porous continuous medium; the oil shale skeleton basically does not deform under the temperature and pressure; the high-temperature mixed gas (oil and gas mixture) has the same flow velocity in the pore space of the oil shale, and the fluid density is uniform, and its fluid flow obeys Darcy's law; it is expected that the oil and gas produced by the decomposition of oil shale are relatively small relative to the amount of injected hot gas, so the influence of oil and gas is ignored; local thermal equilibrium is reached instantly between the fluid and the solid, and it is assumed that the temperature of the two is the same at the same location; considering that the in-situ mining temperature of oil shale is higher than the boiling point of water, the water content is not high, we assume that there is no water phase in the whole process, only gas and liquid phases.

[0057] In one embodiment, in the mass calculation model analysis step, a mass conservation calculation equation is established for the HC gas component, and the equation is as follows:

[0058]

[0059] Among them, F i represents the mass partial derivative operation based on component i, φ represents the formation porosity, S j represents the j-phase saturation, q j represents the j-phase flow rate, the subscript i represents HC gas, j represents gas, φ is the porosity, ξ j is the molar density of phase j, X ij represents the mole fraction of component i in phase j, u j represents the j-phase velocity, Indicates the flow rate of gas injection.

[0060] When fluids flow through oil shale formations, the high-temperature fluids carry heat, transferring and exchanging heat with the rock mass through conduction and convection, directly affecting the temperature distribution within the rock mass. Furthermore, the fluid heating causes kerogen decomposition, altering the rock's porosity. However, the thermal energy involved in the chemical reactions during this entire process is minimal, estimated to be only about one ten-thousandth of the injected heat. Therefore, in the energy calculation model analysis step, an energy calculation model for in-situ fluid injection recovery is constructed based on the kerogen decomposition caused by the fluid heating and the impact of the kerogen decomposition reaction on rock porosity.

[0061] Specifically, in one embodiment, in the energy calculation model analysis step, an energy calculation model corresponding to in-situ production of injection fluid is constructed according to the following logic:

[0062]

[0063] Among them, Fe represents the energy partial derivative operation, ρ j represents the density of phase j, T represents the temperature, and q H represents the heat flow rate of the injection well, U j is the internal energy of phase j, ρ s is the density of kerogen, q j represents the j-phase flow rate, j-phase represents the gas phase, c s is the heat capacity of kerogen, k is the thermal conductivity, H j is the enthalpy of the gas phase.

[0064] The energy change also includes the energy brought in by the injection well and the energy taken out by the production well. Similar to the mass equation, the injected mass is constant, so the injected energy is also constant. The produced energy is mainly carried away by the flow of oil and gas in the form of enthalpy. The empirical calculation formula we use for enthalpy is:

[0065] H i =H ai +H bi T+H ci T 2 +H di T 3 +H ei T 4 +H fi T 5

[0066] Where Hi represents the enthalpy of the i-th component; Hai, Hbi, Hci, Hdi, Hei, and Hfi are all empirical formula coefficients, and T represents temperature. The relationship between internal energy and enthalpy can be simply derived:

[0067]

[0068] The above models are all very complex nonlinear equations, and their coefficients also contain nonlinear terms. For such complex differential equations, it is generally impossible to directly obtain their analytical solutions. They can only be solved by numerical methods to find their approximate solutions. According to the mass equation, energy conservation equation, etc. in the previous mathematical model, the discrete process is analyzed and the solution of the mathematical model is based on the compiled computer program. In one embodiment, in the temperature field data calculation step, the initial parameters set include: initial pressure, initial temperature, injection gas temperature, and production well BHP and heat capacity. As shown in the following table:

[0069] Table 1 Regional initial parameters

[0070] parameter Numerical Initial pressure 101psi Initial temperature 100℉ Injection gas temperature 716℉(380℃) Production well BHP 101psi Heat capacity 1.5 Btu / lbm / ℉

[0071] Furthermore, in one embodiment, the temperature field data calculation step includes the following operations:

[0072] According to the existing initial and boundary conditions as the initial time t n The distribution of mass and temperature fields inside the reservoir rock formation;

[0073] Calculate the next moment, t, by the Newton iteration method n+1 The mass field and temperature field distribution;

[0074] Judge the time situation. If the time does not meet the requirements, repeat the above steps to calculate t n+2 The temperature field data at each moment is then cyclically acquired to obtain the time-domain temperature field variation data during the in-situ mining process. In solving the equation using the Newton iteration method, an initial value is set and the error is calculated after each time step. When the set error is reached, the next time step is performed; otherwise, the iteration continues.

[0075] In actual application, for a certain oil shale reservoir, the analysis and calculation are carried out according to the following ideas:

[0076] ① According to the existing initial and boundary conditions, it is equivalent to calculating t n The distribution of mass field and temperature field inside the oil shale at each moment;

[0077] ② Calculate the next moment, t, by Newton iteration method n+1 The mass field and temperature field distribution;

[0078] ③Judge the time situation. If the time does not meet the requirements, repeat the above steps to calculate t n+2 By repeating this cycle, we can obtain the temporal variation of the temperature field distribution during the in-situ mining of oil shale, as shown in the following example: Figure 3 shown.

[0079] Figure 3In the algorithm for solving the system of equations, the coefficient matrix format of the system of equations is used to improve the efficiency of solution. After setting the initial parameters, the convection term is calculated based on the upwind format, the residual matrix is ​​constructed, and the Jacobi process is used to solve the linear equations. R represents the calculation error, n represents the number of iterations, and n represents the number of iterations. max Indicates the maximum limit of the number of iterations.

[0080] It's worth noting that this invention employs an online method to solve partial differential equations. This approach differs from the conventional approach of differencing both spatial and temporal dimensions by only differentiating the spatial coordinate grid, thereby creating a continuous ordinary differential equation. This approach effectively reduces the number of differential equations and the number of grids, thereby improving solution accuracy and computational efficiency.

[0081] Specifically, in one embodiment, in the temperature field data calculation step, a corresponding isotherm visual graph is generated based on the time domain temperature field variation data during the in-situ mining process of the reservoir area;

[0082] Set the observation time period according to observation requirements and mark the corresponding isotherm part to facilitate users to selectively view and analyze.

[0083] In actual application, in one embodiment, the method also includes conducting an in-situ fluid injection production simulation experiment based on a reservoir sample or reservoir model that is consistent with the geological characteristic data of the reservoir area to be mined according to preset initial parameters, and comparing the results of the simulation experiment with the calculation results obtained using the operation model of this application at the corresponding time for verification.

[0084] In an optional embodiment, the calculation results of the present invention were compared with those of the experimental case, and the temperature accuracy difference was found to be less than 3%. Then, the results were applied to the large-scale in-situ oil shale mining process, and the results were compared when the HC gas injection rate was 50t / day and 100t / day, respectively. Figure 4 The results show that the fluid injection volume and fluid temperature have a significant impact on the temperature distribution of the oil shale formation. The relative error of the calculation is small, and the calculated value is more consistent with the measured value curve. The present invention aims to provide a temperature field simulation method for in-situ production of fluid injection, which can reflect the temperature change process of the oil shale heating process with clear and effective simulation results, and has important guiding significance for the in-situ production technology of oil shale.

[0085] Combining the visual information, we can see that when the injection rate is 100 t / day, the entire temperature field rises rapidly. By 300 days, the temperature of almost the entire field exceeds 350°C. However, when the injection rate is 50 t / day, the area with a temperature exceeding 350°C does not exceed half of the entire field, a significant difference. At an injection rate of 100 t / day, we can see that the temperature rises faster between the heater well and the production well. At 300 and 500 days, we can see that the isotherm changes from a circular arc to a square shape with a convex center. This is due to the large pressure difference between the two wells, which makes it easier for fluid to flow, thus causing a faster temperature change.

[0086] In the fitting calculation process of the above embodiment of the present invention, the phase change of the oil and gas phases and the changes in physical parameters such as porosity and permeability with temperature are taken into account, and a group of flow field control equations are established. Combined with Darcy's law and the gas state equation, the temperature field, pyrolysis rate and gas production of oil shale pyrolysis are numerically simulated. Among them, the gas state equation is used as the basis for calculating the gas temperature and pressure in the numerical simulation. The change of kerogen concentration with time is mainly analyzed to characterize the reaction pyrolysis rate, and the gas production mainly analyzes the methane and C2-C5 hydrocarbon gas production.

[0087] By simulating the oil shale temperature field according to the steps in the above embodiment, the spatiotemporal distribution of the oil shale temperature field under gas injection heating can be obtained. The numerical simulation of the oil shale temperature field proposed in this invention, applied in the field of computer simulation, is more realistic and reliable than existing results, and the algorithm is more rigorous and accurate. The method of this invention can simulate complex reaction processes, thereby simulating scenarios such as fluid flow in formations and temperature field changes over time.

[0088] For simplicity of description, the aforementioned method embodiments are described as a series of actions. However, those skilled in the art should be aware that the present invention is not limited by the order of the actions described, as certain steps can be performed in other orders or simultaneously according to the present invention. Furthermore, those skilled in the art should also be aware that the embodiments described in this specification are preferred embodiments, and the actions and modules involved are not necessarily required for the present invention.

[0089] It should be pointed out that in other embodiments of the present invention, the method can also obtain a new method for simulating the temperature field of oil shale formations for fluid injection heating production by combining one or several of the above embodiments, so as to achieve accurate analysis of in-situ mining process data.

[0090] It should be noted that, based on the method in any one or more of the above-mentioned embodiments of the present invention, the present invention also provides a storage medium, which stores program code that can implement the method described in any one or more of the above-mentioned embodiments. When the code is executed by the operating system, it can implement the above-mentioned method for simulating the temperature field of oil shale formations for fluid injection heating and mining.

[0091] Example 2

[0092] The methods disclosed in the above embodiments of the present invention are described in detail. The methods of the present invention 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 further provides a system for simulating the temperature field of an oil shale formation for fluid injection heating production. This system is used to implement the methods for simulating the temperature field of an oil shale formation for fluid injection heating production described in any one or more of the above embodiments. A specific embodiment is provided below for detailed description.

[0093] Specifically, the oil shale formation temperature field simulation system for fluid injection heating mining provided in an embodiment of the present invention includes:

[0094] A simulation unit setting module is configured to divide the reservoir into a plurality of unit mining spaces according to geological characteristic data of the reservoir to be mined, and preferably to set a group of operating wells in each unit mining space, including a heating well and a production well;

[0095] A mass calculation model analysis module is configured to construct a mass conservation calculation model corresponding to in-situ production of injection fluid for each unit production space based on the mass conservation principle, so as to use the model to analyze the mass field data corresponding to different times during the production implementation process;

[0096] The energy calculation model analysis module is configured to construct an energy calculation model corresponding to in-situ mining of fluid injection based on the principle that high-temperature fluid carries heat and transfers heat with the rock system through conduction and convection, and its impact on the temperature field within the rock mass. This model is then used to analyze energy field data corresponding to different times during the mining process.

[0097] The temperature field data calculation module is configured to introduce preset initial parameters to solve the mass conservation calculation model and energy calculation model based on a discrete process to calculate the initial mass field data and energy field data, and then combine the Newton iteration method to calculate the mass field data and energy field data at subsequent times to characterize the temperature field state of the unit mining space.

[0098] Furthermore, in one embodiment, the system also includes an experimental verification module, which is configured to carry out an in-situ fluid injection production simulation experiment based on a reservoir sample or reservoir model that is consistent with the geological characteristic data of the reservoir area to be mined, according to preset initial parameters, and compare the results of the simulation experiment with the calculation results obtained using the operation model of this application at the corresponding time for verification.

[0099] Optionally, in one embodiment, the mass calculation model analysis module is configured to construct a mass conservation calculation model as shown below:

[0100]

[0101] Among them, F i represents the mass partial derivative operation based on component i, φ represents the formation porosity, S j represents the j-phase saturation, q j represents the j-phase flow rate, the subscript i represents HC gas, j represents gas, φ is the porosity, ξ j is the molar density of phase j, X ij represents the mole fraction of component i in phase j, u j represents the j-phase velocity, Indicates the flow rate of gas injection.

[0102] Furthermore, in one embodiment, the energy calculation model analysis module is configured to construct an energy calculation model corresponding to in-situ mining of fluid injection based on the decomposition of kerogen when the fluid is heated and the influence of the kerogen decomposition reaction on the rock pores.

[0103] Preferably, in one embodiment, the energy calculation model analysis module is configured to construct an energy calculation model corresponding to in-situ production of injection fluid according to the following logic:

[0104]

[0105] Among them, Fe represents the energy partial derivative operation, ρ j represents the density of phase j, T represents the temperature, and q H represents the heat flow rate of the injection well, q j Indicates the j-phase flow rate, j-phase represents the gas phase, U j is the internal energy of phase j, ρ s is the density of kerogen, c s is the heat capacity of kerogen, k is the thermal conductivity, H j is the enthalpy of the gas phase.

[0106] In an optional embodiment, the initial parameters set by the temperature field data calculation module include: initial pressure, initial temperature, injection gas temperature, and production well BHP and heat capacity.

[0107] Preferably, in one embodiment, the temperature field data calculation module is further configured to perform the following operations:

[0108] The initial and boundary conditions to be solved are taken as the initial time t n The mass and temperature field distribution inside the reservoir rock formation, where only the time differential term is retained by differentiating the spatial coordinate grid when solving the differential equation, making it a time-continuous ordinary differential equation;

[0109] Calculate the next moment, t, by the Newton iteration method n+1 The mass field and temperature field distribution;

[0110] Judge the time situation. If the time does not meet the requirements, repeat the above operation to calculate t n+2 The temperature field data at each moment is obtained through cyclic operation, and the time domain temperature field change data during the in-situ mining process of the reservoir is obtained.

[0111] As a further improvement of the present invention, in one embodiment, the system further includes a data recording and display module, which is configured as follows:

[0112] The corresponding isotherm visual graph is generated based on the time domain temperature field change data during the in-situ mining process of the reservoir area;

[0113] Set the observation time period according to observation requirements and mark the corresponding isotherm part to facilitate users to selectively view and analyze.

[0114] In the oil shale formation temperature field simulation system for fluid injection heating mining provided by the embodiment of the present invention, each module or unit structure can operate independently or in combination according to actual setting requirements and simulation calculation requirements to achieve corresponding technical effects.

[0115] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should extend to equivalent substitutions of these features understood by those skilled in the relevant art. It should also be understood that the terminology used herein is for the purpose of describing specific embodiments only and is not intended to be limiting.

[0116] The phrase "one embodiment" mentioned in the specification means that a particular feature, structure, or characteristic described in conjunction with the embodiment is included in at least one embodiment of the present invention. Therefore, the phrase "one embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0117] Although the embodiments disclosed herein are as described above, the contents described herein are merely embodiments for facilitating understanding of the present invention and are not intended to limit the present invention. Any person skilled in the art may make any modifications and variations in the form and details of the embodiments without departing from the spirit and scope of the present invention. However, the scope of patent protection of the present invention shall remain subject to the scope defined by the appended claims.

Claims

1. A method for simulating the temperature field of oil shale formations during fluid injection heating mining, characterized in that: The method comprises: The simulation unit setting step is to divide the reservoir into a number of unit mining spaces according to the geological characteristic data of the reservoir to be mined, and it is appropriate to set up a group of operating wells in each unit mining space, including a heating well and a production well; The mass calculation model analysis steps are as follows: Based on the mass conservation principle, a mass conservation calculation model corresponding to in-situ production of injection fluid is constructed for each unit production space, so as to use the model to analyze the mass field data corresponding to different times during the production implementation process; Energy calculation model analysis steps: Based on the principle that high-temperature fluid carries heat and transfers heat with the rock system through conduction and convection, and its impact on the temperature field within the rock mass, an energy calculation model corresponding to fluid injection in-situ mining is constructed. This model is used to analyze the energy field data corresponding to different times during the mining implementation process; The temperature field data calculation step introduces preset initial parameters to solve the mass conservation calculation model and energy calculation model based on a discrete process to calculate the initial mass field data and energy field data, and then combines the Newton iteration method to calculate the mass field data and energy field data at subsequent times to characterize the temperature field state of the unit mining space.

2. The method according to claim 1, characterized in that The method also includes conducting an in-situ fluid injection production simulation experiment based on a reservoir sample or reservoir model that is consistent with the geological characteristic data of the reservoir area to be mined according to preset initial parameters, and comparing the results of the simulation experiment with the calculation results obtained using the operation model of this application at the corresponding time for verification.

3. The method according to claim 1, characterized in that In the mass computational model analysis step, a mass conservation computational model is constructed as shown below: Among them, F i represents the mass partial derivative operation based on component i, φ represents the formation porosity, S j represents the j-phase saturation, q j represents the j-phase flow rate, the subscript i represents HC gas, j represents gas, φ is the porosity, ξ j is the molar density of phase j, X ij represents the mole fraction of component i in phase j, u j represents the j-phase velocity, q j W Indicates the flow rate of gas injection.

4. The method according to claim 1, wherein In the energy calculation model analysis step, based on the fact that the fluid decomposes the kerogen when heated, and combining the effect of the kerogen decomposition reaction on the rock pores, an energy calculation model corresponding to the in-situ production of fluid injection is constructed.

5. The method according to claim 1, wherein In the energy calculation model analysis step, the energy calculation model corresponding to the in-situ production of injection fluid is constructed according to the following logic: Among them, Fe represents the energy partial derivative operation, ρ j represents the density of phase j, T represents the temperature, and q H represents the heat flow rate of the injection well, q j Indicates the j-phase flow rate, j-phase represents the gas phase, U j is the internal energy of phase j, ρ s is the density of kerogen, c s is the heat capacity of kerogen, k is the thermal conductivity, H j is the enthalpy of the gas phase.

6. The method according to claim 1, characterized in that In the temperature field data calculation step, the initial parameters set include: initial pressure, initial temperature, injection gas temperature, and production well BHP and heat capacity.

7. The method according to claim 1, characterized in that The temperature field data calculation step includes the following operations: The initial and boundary conditions to be solved are taken as the initial time t n The mass and temperature field distribution inside the reservoir rock formation, where only the time differential term is retained by differentiating the spatial coordinate grid when solving the differential equation, making it a time-continuous ordinary differential equation; Calculate the next moment, t, by the Newton iteration method n+1 The mass field and temperature field distribution; Judge the time situation. If the time does not meet the requirements, repeat the above steps to calculate t n+2 The temperature field data at each moment is obtained through cyclic operation, and the time domain temperature field change data during the in-situ mining process of the reservoir is obtained.

8. The method according to claim 1, characterized in that The method further comprises: generating a corresponding isotherm visual graph based on the time domain temperature field variation data during the in-situ mining process of the reservoir area; Set the observation time period according to observation requirements and mark the corresponding isotherm part to facilitate users to selectively view and analyze.

9. A storage medium, characterized in that: The storage medium stores program code that can implement the method according to any one of claims 1 to 8.

10. A temperature field simulation system for oil shale formations produced by fluid injection heating, characterized in that: The system executes the method according to any one of claims 1 to 8.

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