Method and system for determining in-situ limit exploitation depth of oil shale

Abstract

The invention discloses a method and system for determining the in-situ limit exploitation depth of oil shale, and the method comprises the steps: measuring the permeability under different depths according to an oil shale sample of an oil shale in-situ region to be evaluated; performing a pyrolysis experiment on the oil shale sample to obtain the composition of each simulated product and the components of each simulated product changing along with the temperature, and fitting a pre-constructed kerogen pyrolysis-based multi-step total reaction model on the basis of the composition and the components, so as to obtain fitted model coefficients and reaction kinetic parameters; predicting a formation temperature field formed on the basis of a heating condition of high-temperature fluid injection in the current formation, and predicting a yield change curve on the basis of the formation temperature field in combination with the permeability at different depths, the model coefficients and the reaction kinetic parameters; and establishing an income prediction model related to the to-be-evaluated oil shale in-situ area, and obtaining the limit mining depth when the income value is zero according to the yield change curve.

Description

Technical Field

[0001] The present invention relates to the technical field of in-situ mining of oil shale, and in particular to a method and system for determining the in-situ limiting mining depth of oil shale. Background Art

[0002] As conventional oil and gas resources become increasingly depleted, they are increasingly unable to meet the needs of economic development. There is an urgent need to find new alternative resources. Shale oil recovery through thermal reforming is considered a technology that can effectively utilize shale oil. By heating the formation, solid organic matter is converted into oil and gas.

[0003] Currently, existing in-situ extraction technologies—inductively coupled plasma (ICP) heating and high-temperature fluid heating—are the two most mature in-situ extraction technologies. Previous mechanistic studies have shown that the permeability of oil shale decreases with increasing depth, exhibiting significant stress sensitivity. This decreases formation permeability with increasing depth, prolongs extraction time, and significantly impacts secondary reactions, leading to lower oil production under the same time conditions. Furthermore, increased burial depth increases well depth, increasing fixed costs and impacting the overall economic viability of extraction. However, existing understanding of this aspect remains at a qualitative level, lacking quantitative analysis, making it difficult to guide the development of in-situ oil shale extraction plans and investment decisions.

[0004] Although some small-scale experiments have been conducted in recent years, data on cost-effectiveness is lacking. The impact of target stratum depth on production costs is unclear, and the depth of resources suitable for both extraction technologies remains poorly understood. Consequently, existing technologies lack a method for studying the critical depth of oil shale in a horizontal well heating shale scenario. Summary of the Invention

[0005] The purpose of the present invention is to provide a quantitative evaluation scheme that can solve the influence of the buried depth of the comprehensive selected target layer and the profitability in the in-situ heating oil shale heating mining technology.

[0006] In order to solve the above technical problems, an embodiment of the present invention provides a method for determining the in-situ limit mining depth of oil shale, comprising: measuring the permeability at different depths based on oil shale samples in the in-situ area of ​​the oil shale to be evaluated; performing a pyrolysis experiment on the oil shale sample to obtain the composition of each pseudo-product and the components of each pseudo-product that change with temperature, based on which, fitting a pre-constructed multi-step total reaction model based on kerogen pyrolysis to obtain the fitted model coefficients and reaction kinetic parameters; predicting the formation temperature field formed by the heating conditions based on high-temperature fluid injection in the current formation, based on which, combining the permeability at different depths, the model coefficients and the reaction kinetic parameters, predicting the production change curve; establishing a profit prediction model related to the in-situ area of ​​the oil shale to be evaluated, and obtaining the limit mining depth when the profit value is zero from the production change curve.

[0007] Preferably, in performing a pyrolysis experiment on the oil shale sample to obtain the composition of each pseudo-product and the temperature-dependent component of each pseudo-product, based on which, fitting a pre-constructed multi-step overall reaction model based on kerogen pyrolysis to obtain the fitted model coefficients and reaction kinetic parameters comprises: conducting heating pyrolysis experiments at a preset heating rate and under different pressure conditions, thereby recording the composition of each pseudo-product and the temperature-dependent component of each pseudo-product; and establishing the multi-step overall reaction model based on kerogen pyrolysis, wherein the multi-step overall reaction model is:

[0008]

[0009]

[0010]

[0011]

[0012]

[0013]

[0014] Where m represents the total number of pseudo-products, X1, X2…X i …X m represents the pseudo-products of the 1st, 2nd…i…mth reactions, k1, k2…k i …k m Represents the 1st, 2nd…i…mth reaction formula, Representing a model coefficient matrix; establishing an error function between the experimental measurement value and the theoretical value of the composition of each pseudo-product and the component of each pseudo-product that changes with temperature, thereby solving the error function based on the component content of each pseudo-product that changes with temperature obtained by experimental measurement and the theoretical value of the component content of each fitting that changes with temperature under corresponding conditions to obtain the model coefficients and reaction kinetic parameters, wherein the reaction kinetic parameters include but are not limited to pre-exponential factor and activation energy.

[0015] Preferably, the error function is expressed using the following expression:

[0016] F(E i ,A i ,a i,j )=∑(X exp -X cal ) 2

[0017] Among them, F represents the objective function, E i represents the activation energy parameter of the i-th reaction, a i,j Represents the elements of the model coefficient matrix, A i represents the pre-exponential factor parameter of the i-th reaction, X exp Indicates the theoretical value of component content, X cal An experimentally measured value representing the amount of a component.

[0018] Preferably, the step of predicting the formation temperature field formed by the heating conditions of the current formation based on the injection of high-temperature fluid includes: establishing a formation temperature field prediction model to obtain the distribution characteristics of the formation temperature field under the well pattern heating conditions. In the process of constructing the formation temperature field prediction model, the temperature fields generated by the electric heaters in different horizontal wells are considered and superimposed calculations are performed, including: considering the seepage of high-temperature fluid in the oil shale formation, the high-temperature fluid carries heat to transfer and exchange heat with the rock system in the form of conduction and convection, and its control equation is:

[0019]

[0020] Among them, F e represents the energy change function at different positions in the formation, t represents time, represents porosity, j represents the sequence number of different phase fluids, ρ j represents the density of the j-th phase fluid, S j represents the fluid saturation of the j-th phase fluid, u j represents the seepage velocity of the j-th phase fluid, U j represents the internal energy of the j-th phase fluid, H j represents the enthalpy of the j-th phase fluid, T represents the temperature, represents the temperature gradient, ρ s represents the density of kerogen, c s represents the specific heat capacity of kerogen, k represents the thermal conductivity, represents the well injection flow rate, q H Represents fluid energy.

[0021] Preferably, the step of predicting the production change curves of various hydrocarbon components in the in-situ area of ​​the oil shale to be evaluated includes: simulating the pyrolysis process under actual well network heating conditions based on the solved model coefficients and reaction kinetic parameters; establishing mass conservation equations for different pseudo-product components using the principle of mass conservation; solving the mass conservation equations based on the mass conservation equations for different pseudo-product components, combined with the permeability of the oil shale at different depths, the solved pyrolysis process, and the predicted formation temperature field distribution characteristics, thereby obtaining the production change curve in the in-situ area of ​​the oil shale to be evaluated under a given well network pattern, given formation heating conditions and given depth conditions.

[0022] Preferably, the mass conservation equations of the different pseudo-product components are expressed using the following expressions:

[0023]

[0024] Among them, F i represents the mass of the ith pseudo-product, t represents the time, represents porosity, j represents the sequence number of different phase fluids, ξ j represents the molar density of the j-phase fluid, ξ j =p j / ZRT, Z represents the gas compressibility coefficient, R represents the constant, T represents the temperature, p j represents the pressure of the j-phase fluid, X ij represents the mole fraction of the i-th pseudo-product component in the j-th phase fluid, u j represents the seepage velocity of the j-phase fluid, K represents the rock permeability, k rj represents the relative permeability of the j-phase fluid, μ j represents the viscosity of the j-phase fluid, represents the pressure gradient of the j-phase fluid, r k represents the reaction rate of the kth chemical reaction in the multi-step overall reaction model, v ij,k represents the coefficient of the i-th pseudo-product component in the j-th phase fluid in the k-th chemical reaction, Indicates the well injection rate.

[0025] Preferably, in the step of establishing a revenue prediction model related to the in-situ area of ​​the oil shale to be evaluated and obtaining the limit mining depth when the revenue value is zero from the production change curve, it includes: drawing the production change curve under different depth conditions according to the permeability of the oil shale at different depths; and fitting the revenue value curve that changes with depth according to the production change curve under the different depth conditions using the revenue prediction model, so as to obtain the well depth when the revenue value is zero, which is recorded as the limit mining depth.

[0026] Preferably, the revenue prediction model is expressed using the following expression:

[0027]

[0028] Ci=Qi×Po

[0029] Co=(P drl ·N w +P op T0+C dv )

[0030] P drl =P fix +P cph ·H

[0031] N w =N ht +N pd β

[0032] Among them, NPV represents the profit value, Ci represents the annual profit, Co represents the annual expenditure, r represents the interest rate, i represents the benchmark rate of return, N ht Number of heating wells, N pd represents the number of production wells, β represents the drilling cost ratio of production wells to heating wells, P drl represents the single well drilling cost, N w represents the well index, T0 represents the mining time, n represents the sequence number of the mining time, Qi represents the oil production, Po represents the crude oil price, C dv represents fixed investment in equipment, P op represents the operating cost, P fix represents the fixed cost of drilling a single well, P cph represents the drilling cost per meter, and H represents the well depth.

[0033] On the other hand, an embodiment of the present invention provides a system for determining the in-situ limit mining depth of oil shale, the system being used to implement the method described above, the system comprising: a permeability measurement module, configured to measure the permeability at different depths based on oil shale samples in the in-situ area of ​​the oil shale to be evaluated; a reaction parameter fitting module, configured to perform a pyrolysis experiment on the oil shale sample to obtain the composition of each pseudo-product and the components of each pseudo-product that change with temperature, based on which, fit a pre-constructed multi-step total reaction model based on kerogen pyrolysis to obtain the fitted model coefficients and reaction kinetic parameters; a production solution module, configured to predict the formation temperature field formed by the heating conditions based on high-temperature fluid injection in the current formation, based on which, combined with the permeability at different depths, the model coefficients and reaction kinetic parameters, predict the production change curve; a mining depth generation module, configured to establish a revenue prediction model related to the in-situ area of ​​the oil shale to be evaluated, and obtain the limit mining depth when the revenue value is zero from the production change curve.

[0034] Preferably, the production solution module includes: a temperature field prediction unit, which is configured to predict the formation temperature field formed by the heating conditions based on high-temperature fluid injection in the current formation; a pyrolysis process calculation unit, which is configured to simulate the pyrolysis process under actual well network heating conditions based on the solved model coefficients and reaction kinetic parameters; a mass equation construction unit, which is configured to adopt the mass conservation principle to establish a mass conservation equation for different pseudo-product components; a production curve generation unit, which is configured to solve the mass conservation equation based on the mass conservation equation of the different pseudo-product components, combined with the oil shale permeability at different depths, the solved pyrolysis process, and the predicted formation temperature field distribution characteristics, so as to obtain the production change curve in the in-situ area of ​​the oil shale to be evaluated under a given well network pattern, given formation heating conditions and given depth conditions.

[0035] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0036] This invention proposes a method and system for determining the in-situ maximum mining depth of oil shale. This method and system include experimental steps for analyzing the relationship between depth and formation permeability, constructing an NPV prediction model related to burial depth, predicting the formation temperature field, predicting the production of each component, and predicting the maximum depth. This method determines the maximum mining depth based on a given mining area, heating well pattern, and heating temperature parameters. This addresses the issue of quantitatively evaluating the impact of target stratum burial depth on selected areas and the economics of in-situ heating oil shale mining schemes.

[0037] 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

[0038] 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:

[0039] Figure 1 Schematic diagram of the steps of a method for determining the in-situ limit mining depth of oil shale according to an embodiment of the present application.

[0040] Figure 2 Schematic diagram of formation permeability change curve under different confining pressure conditions in the method for determining the in-situ limit mining depth of oil shale in an embodiment of the present application.

[0041] Figure 3 This is a schematic diagram of a production change curve in a one-injection-four-production five-point well pattern mode in a method for determining the in-situ limit production depth of oil shale in an embodiment of the present application.

[0042] Figure 4 This is a schematic diagram of a curve showing the relationship between well depth and revenue value in a method for determining the in-situ limit mining depth of oil shale according to an embodiment of the present application.

[0043] Figure 5 This is a schematic structural diagram of a system for determining the in-situ limit mining depth of oil shale according to an embodiment of the present application. DETAILED DESCRIPTION

[0044] The following describes the embodiments of the present invention in detail with reference to the accompanying drawings and examples, so that the present invention can fully understand how to apply technical means to solve technical problems and achieve technical effects, and thus implement the invention accordingly. It should be noted that, as long as no conflict exists, the various embodiments of the present invention and the various features of the embodiments can be combined with each other, and the resulting technical solutions are all within the scope of protection of the present invention.

[0045] In addition, the steps shown in the flowchart of the accompanying drawings can be executed in a computer system such as a set of computer executable instructions. Also, although a logical order is shown in the flowchart, in some cases, the steps shown or described can be performed in a different order than here.

[0046] 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.

[0047] As conventional oil and gas resources become increasingly depleted, they are increasingly unable to meet the needs of economic development. There is an urgent need to find new alternative resources. Shale oil recovery through thermal reforming is considered a technology that can effectively utilize shale oil. By heating the formation, solid organic matter is converted into oil and gas.

[0048] Currently, existing in-situ extraction technologies—inductively coupled plasma (ICP) heating and high-temperature fluid heating—are the two most mature in-situ extraction technologies. Previous mechanistic studies have shown that the permeability of oil shale decreases with increasing depth, exhibiting significant stress sensitivity. This decreases formation permeability with increasing depth, prolongs extraction time, and significantly impacts secondary reactions, leading to lower oil production under the same time conditions. Furthermore, increased burial depth increases well depth, increasing fixed costs and impacting the overall economic viability of extraction. However, existing understanding of this aspect remains at a qualitative level, lacking quantitative analysis, making it difficult to guide the development of in-situ oil shale extraction plans and investment decisions.

[0049] Although some small-scale experiments have been conducted in recent years, data on cost-effectiveness is lacking. The impact of target stratum depth on production costs is unclear, and the depth of resources suitable for both extraction technologies remains poorly understood. Consequently, existing technologies lack a method for studying the critical depth of oil shale in a horizontal well heating shale scenario.

[0050] In order to solve the problems in the above-mentioned background technology, the embodiment of the present application proposes a method and system for determining the in-situ limit mining depth of oil shale. The method and system first carried out a pilot test of high-temperature fluid heating of underground oil shale, and determined the relationship between well depth and formation permeability; then, based on the pyrolysis experiment, a prediction of the amount of pyrolysis product generated was established, and then, using numerical simulation technology, a model that comprehensively reflects the formation temperature field and the pyrolysis process was established based on the mechanism research, so as to study the limit mining depth when considering the benefit value. To this end, the problem of the influence of the buried depth of the selected target layer and the quantitative evaluation of the benefit value in the in-situ heating oil shale mining plan was solved.

[0051] Figure 1 This is a schematic diagram of the steps of the method for determining the in-situ limit mining depth of oil shale in an embodiment of the present application. Figure 1 , the steps of the method for determining the in-situ limit mining depth of oil shale ("well depth determination method") described in an embodiment of the present invention are described.

[0052] Step S110 measures the permeability at different depths based on the oil shale samples in the in-situ area of ​​the oil shale to be evaluated.

[0053] In step S110, a permeability test is conducted using oil shale samples from the in-situ area of ​​the oil shale to be evaluated. First, the confining pressure data corresponding to different formation depths are determined, and the state changes of the samples under different confining pressures during the heating process are simulated to measure the permeability values ​​of the oil shale at different depths during the heating process. Further, a formation permeability change curve under different well depths (or confining pressures) of the in-situ area of ​​the oil shale to be evaluated is drawn. Figure 2 .

[0054] Step S120 conducts an indoor pyrolysis experiment on the oil shale samples collected from the in-situ area of ​​the oil shale to be evaluated to obtain the composition of each pseudo-product and the components of each pseudo-product that change with temperature. Then, according to the component content (experimental) data of different pseudo-products that change with temperature, a pre-constructed multi-step overall reaction model based on kerogen pyrolysis is fitted to obtain the fitted model coefficients and reaction kinetic parameters.

[0055] In step S120, an indoor pyrolysis experiment is first conducted on the oil shale sample. Specifically, the pyrolysis experiment is conducted at a preset heating rate and under different pressure conditions to record the composition of each pseudo-product and its temperature-dependent composition. In one embodiment, the preset heating rate matches the actual formation heating rate.

[0056] Specifically, pyrolysis experiments were conducted at different pressures (P1, P2, and P3) using actual formation heating rates. Hydrocarbon components were combined based on similarity in properties and carbon number to form pseudo-components. This yielded data on the compositional content of each redefined pseudo-product, the content of other non-hydrocarbon components, and the temperature-dependent compositional content of each pseudo-product. In this embodiment, the pseudo-products include at least CH4, moisture, light oil, and heavy oil.

[0057] Then, according to the experimentally measured component content data of each fitting object, a pre-constructed multi-step overall reaction model based on kerogen pyrolysis was fitted to solve the model coefficients and reaction kinetic parameters.

[0058] Specifically, a multi-step overall reaction model based on kerogen pyrolysis was first established. This multi-step reaction model for in-situ kerogen pyrolysis describes the primary kerogen cracking and the secondary cracking of each fraction produced by the primary kerogen cracking using a first-order reaction model. Assume that there are m components of the fitted products during the in-situ kerogen pyrolysis process. This multi-step overall reaction model reflects the reaction pattern of the pyrolysis process and is expressed as follows:

[0059]

[0060]

[0061]

[0062]

[0063]

[0064]

[0065] Among them, X1, X2…X i …X m They represent the pseudo-products of the 1st, 2nd…i…mth reactions, k1, k2…k i …k m Represent the 1st, 2nd…i…mth reaction formulas respectively, Represents the model coefficient matrix for the multistep overall reaction model.

[0066] In solving the multi-step overall reaction model, an error function is first established between the experimentally measured values ​​of the composition of each pseudo-product and the temperature-dependent components of each pseudo-product and the corresponding theoretical values. The error function is then solved based on the experimentally measured temperature-dependent component content of each pseudo-product and the theoretical temperature-dependent component content of each fitted product under the corresponding conditions to obtain the model coefficients and reaction kinetic parameters. Kinetic parameters include, but are not limited to, pre-exponential factors and activation energies.

[0067] The error function is expressed as follows:

[0068] F(E i ,A i ,a i,j )=∑(X exp -X cal ) 2 (2)

[0069] In formula (2), F represents the error objective function, E i represents the activation energy parameter of the i-th reaction, a i,j Represents the elements of the model coefficient matrix, Ai represents the pre-exponential factor parameter of the i-th reaction, X exp Indicates the theoretical value of component content, X cal An experimentally measured value representing the amount of a component.

[0070] In the embodiment of the present invention, the process of obtaining the model coefficients and reaction kinetic parameters is to solve the experimental values ​​(X exp ) and the theoretical value under corresponding conditions (X cal ). After completing the minimum value fit under the preset constraints, the multi-step reaction equation coefficients and reaction kinetic parameters are obtained. Table 1 shows an example of the reaction kinetic parameter table required after solving the multi-step overall reaction model.

[0071] Table 1

[0072]

[0073] After the multi-step overall reaction model is solved, the process proceeds to step S130.

[0074] Step S130 predicts the formation temperature field formed by the heating conditions based on high-temperature fluid injection in the current formation, and predicts the production change curve in the in-situ area of ​​the oil shale to be evaluated based on the predicted formation temperature distribution characteristics, combined with the permeability at different depths, and the fitted model coefficients and reaction kinetic parameters.

[0075] In step S130, the formation temperature field generated by the heating conditions of the current formation due to the injection of high-temperature fluids must first be predicted. Specifically, a formation temperature field prediction model under the heating conditions of the current well pattern to be studied is first established to obtain the distribution characteristics of the formation temperature field under the heating conditions of the well pattern.

[0076] In the process of constructing the formation temperature field prediction model, the temperature fields generated by the electric heaters in different horizontal wells are considered and superimposed calculations are performed, including:

[0077] During the in-situ mining of oil shale, the seepage of high-temperature fluid in the oil shale formation is considered. The high-temperature fluid carries heat and transfers and exchanges heat with the rock system in the form of conduction and convection. The temperature control equation at different locations is:

[0078]

[0079] Among them, F e represents the energy change function at different positions in the formation, t represents time, represents porosity, j represents the sequence number of different phase fluids, ρ j represents the density of the j-th phase fluid, Sj represents the fluid saturation of the jth phase fluid (i.e., the percentage of the rock pore volume), u j represents the seepage velocity of the j-th phase fluid, U j represents the internal energy of the j-th phase fluid (including the kinetic energy due to molecular motion and the potential energy due to intermolecular forces), H j represents the enthalpy of the j-th phase fluid, T represents the temperature, represents the temperature gradient, ρ s represents the density of kerogen, c s represents the specific heat capacity of kerogen, k represents the thermal conductivity, represents the well injection flow rate, q H Represents fluid energy (the energy carried by the outflowing fluid, including internal energy and mechanical energy generated by the flow).

[0080] Therefore, after completing the construction of the formation temperature field distribution prediction model in step S130, the basic parameters of the rock mass, as well as the target layer thickness, mining area range and basic geological parameters of the oil shale in-situ area to be evaluated can be used to solve the formation temperature field distribution characteristics of the entire oil shale in-situ area to be evaluated under the actual well network heating conditions.

[0081] In one embodiment, the basic rock mass parameters can be measured based on oil shale samples from the in-situ area of ​​the oil shale to be evaluated. Specifically, oil shale samples are taken from the in-situ area of ​​the oil shale to be evaluated, and the basic rock mass parameters are measured. In this embodiment of the present invention, the basic rock mass parameters include, but are not limited to, horizontal thermal conductivity, vertical thermal conductivity, kerogen weight percentage, unit molecular weight, kerogen density, rock density, carbon char density, rock thermal conductivity, rock specific heat capacity, and porosity.

[0082] Next, after obtaining the formation temperature field distribution characteristics, step S130 of the embodiment of the present invention further predicts the production change curve of each hydrocarbon component in the in-situ area of ​​the oil shale to be evaluated.

[0083] Specifically, in the first step, the pyrolysis process under actual well pattern heating conditions is simulated based on the solved model coefficients and reaction kinetic parameters.

[0084] In the first step, pyrolysis experiments were conducted on in-situ oil shale samples from the area under evaluation to obtain data on the degree or percentage of pyrolysis of various organic products. Using this experimental data, combined with the solved model coefficients and reaction kinetic parameters, as well as the formation temperature distribution characteristics, a numerical simulation algorithm was employed to predict the pyrolysis process under actual formation slow heating conditions. The actual formation slow heating conditions refer to the predicted formation temperature distribution characteristics.

[0085] The second step is to use the principle of mass conservation to establish mass conservation equations for different pseudo-product components. The mass conservation equations for different pseudo-product components are expressed as follows:

[0086]

[0087] In formula (4), F i represents the mass of the ith pseudo-product, t represents the time, represents porosity, j represents the sequence number of different phase fluids, ξ j represents the molar density of the j-phase fluid, ξ j =p j / ZRT, Z represents the gas compressibility coefficient, R represents the constant, T represents the temperature, p j represents the pressure of the j-phase fluid, X ij represents the mole fraction of the i-th pseudo-product component in the j-th phase fluid, u j represents the seepage velocity of the j-phase fluid, K represents the rock permeability, k rj represents the relative permeability of the j-phase fluid, μ j represents the viscosity of the j-phase fluid, represents the pressure gradient of the j-phase fluid, r k represents the reaction rate of the kth chemical reaction in the multi-step overall reaction model, v ij,k represents the coefficient of the i-th pseudo-product component in the j-th phase fluid in the k-th chemical reaction, Indicates the well injection rate.

[0088] The third step is to solve the mass conservation equation for each pseudo-product component, combining the oil shale permeability at different depths, the calculated pyrolysis process under actual well pattern heating conditions, and the predicted formation temperature distribution characteristics. This yields the production curves for each hydrocarbon component in the in-situ area of ​​the oil shale under the given well pattern, given formation heating conditions, and given depth. The given formation heating conditions are the predicted formation temperature distribution characteristics.

[0089] It should be noted that the given well pattern described herein is the well pattern currently under study, which can be a five-point well pattern with one injection and four production, a five-point well pattern with four injections and one production, a two-injection and one production well pattern, or other reasonable well pattern suitable for in-situ oil shale mining scenarios, and the present invention does not make specific limitations on this. Figure 3 As shown, Figure 3 The production change curve under the one-injection-four-production-five-point well pattern is shown.

[0090] Therefore, after the mass conservation equation is solved and the yield change curve is obtained, the process proceeds to step S140.

[0091] Step S140 establishes a profit prediction model related to the in-situ area of ​​the oil shale to be evaluated, and obtains the limit mining depth when the profit value is zero from the production change curve obtained in step S130.

[0092] In step S140, first, production variation curves at different depths are plotted based on the oil shale permeability at different depths. Specifically, the production variation curve at a specific well depth obtained in step S130 is combined with the oil shale permeability at different depths to convert the production variation curve at the specified well depth into production variation curves at different depths.

[0093] Then, based on the production change curves under different depth conditions, the pre-built profit prediction model is used to fit the profit value curve that changes with depth, so as to obtain the well depth when the profit value is zero, which is recorded as the maximum mining depth.

[0094] In one embodiment, the revenue prediction model is expressed using the following expression:

[0095]

[0096] Ci=Qi×Po (6)

[0097] Co=(P drl ·N w +P op T0+C dv ) (7)

[0098] P drl =P fix +P cph ·H (8)

[0099] N w =N ht +N pd β (9)

[0100] In formulas (5) to (9), NPV represents the profit value; Ci represents the annual profit; Co represents the annual expenditure; r represents the interest rate; i represents the benchmark rate of return; N ht Number of heating wells, in units of wells; N pd represents the number of production wells, in units of wells; β represents the drilling cost ratio of production wells to heating wells; P drl Indicates the cost of drilling a single well, in Yuan / well; N wrepresents the well index; T0 represents the mining time, in months / years; n represents the sequence number of the mining time; Qi represents the oil production, in tons; Po represents the crude oil price, in yuan / ton; C dv represents fixed investment in equipment, in yuan; P op Indicates the operating cost, in yuan / day; P fix represents the fixed cost of drilling a single well; P cph represents the drilling cost per meter; H represents the well depth.

[0101] To calculate the ultimate mining depth, we first calculate production data at different well depths based on the production curves at different depths. We can also obtain the formation permeability and drilling costs at different depths, and then use the aforementioned revenue prediction model to calculate the revenue value (e.g., net present value) at different depths. We then fit the revenue value curve that varies with depth, and record the well depth at which the revenue value is zero as the ultimate mining depth.

[0102] Example

[0103] Take a mining area of ​​90*90 meters square as an example, the target layer thickness is 18 meters, the oil content is 8%, the cost of drilling and cementing a single well is 800,000 yuan, the surface equipment is 5 million yuan, and the operating cost is 2.3 million yuan / year. The relationship between depth and permeability is the stress sensitivity data of permeability, such as Figure 2 As shown; and the relationship between depth and net present value, as shown Figure 4 According to the well depth determination method described in the embodiment of the present invention, under the conditions of basic parameters and costs, the maximum mining depth is 1550 meters.

[0104] On the other hand, based on the above-mentioned well depth determination method, an embodiment of the present invention further provides a system for determining the in-situ limit production depth of oil shale (also referred to as a "well depth determination system"). The system is used to implement the well depth determination method described above.

[0105] Figure 5 Schematic diagram of the structure of the system for determining the in-situ limit mining depth of oil shale according to an embodiment of the present application. Figure 5 As shown, the well depth determination system according to the embodiment of the present invention includes: a permeability determination module 510 , a reaction parameter fitting module 520 , a production solution module 530 and a production depth generation module 540 .

[0106] Specifically, the permeability determination module 510 is implemented according to the method described in step S110 above and is configured to determine the permeability at different depths based on the oil shale samples in the in-situ area of ​​the oil shale to be evaluated. The reaction parameter fitting module 520 is implemented according to the method described in step S120 above and is configured to perform a pyrolysis experiment on the oil shale samples to obtain the composition of each pseudo-product and the temperature-dependent components of each pseudo-product. Based on this, a pre-constructed multi-step total reaction model based on kerogen pyrolysis is fitted to obtain the fitted model coefficients and reaction kinetic parameters. The yield solution module 530 is implemented according to the method described in step S130 above and is configured to predict the formation temperature field formed by the heating conditions of the current formation based on the high-temperature fluid injection. Based on this, the yield variation curve in the in-situ area of ​​the oil shale to be evaluated is predicted in combination with the permeability at different depths and the solved model coefficients and reaction kinetic parameters. The mining depth generation module 540 is implemented according to the method described in step S140 above and is configured to establish a revenue prediction model related to the in-situ area of ​​the oil shale to be evaluated and obtain the limit mining depth when the revenue value is zero from the revenue variation curve.

[0107] In one embodiment, the production solution module 530 includes a temperature field prediction unit 531, a pyrolysis progress calculation unit 532, a mass equation construction unit 533, and a production curve generation unit 534. The temperature field prediction unit 531 is configured to predict the formation temperature field generated by the heating conditions of the current in-situ formation due to high-temperature fluid injection. The pyrolysis progress calculation unit 532 is configured to simulate the pyrolysis process under actual well pattern heating conditions based on the solved model coefficients and reaction kinetic parameters. The mass equation construction unit 533 is configured to establish mass conservation equations for different pseudo-product components using the principle of mass conservation. The production curve generation unit 534 is configured to solve the mass conservation equations for different pseudo-product components based on the mass conservation equations, combined with the oil shale permeability at different depths, the solved pyrolysis progress, and the predicted formation temperature field distribution characteristics, to obtain production change curves for each hydrocarbon component in the in-situ area of ​​the oil shale to be evaluated under a given well pattern, given formation heating conditions, and given depth.

[0108] The present invention discloses a method and system for determining the in-situ maximum mining depth of oil shale. The method and system include experimental steps for determining the relationship between depth and formation permeability, constructing an NPV prediction model related to burial depth, predicting the formation temperature field, predicting the production of each component, and predicting the maximum depth. The present invention determines the maximum mining depth based on a given range of mining areas, heating well pattern, and heating temperature parameters, addressing the quantitative evaluation of the impact of target stratum burial depth on the economic feasibility of in-situ heating oil shale mining schemes.

[0109] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any changes or substitutions that can be easily conceived by anyone skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be based on the scope of protection of the claims.

[0110] In the description of the present invention, unless otherwise specified, "plurality" means two or more; terms such as "upper," "lower," "left," "right," "inner," "outer," "front end," "rear end," "head," and "tail" indicate positions or relationships based on those shown in the accompanying drawings. These terms are intended solely to facilitate the description of the present invention and simplify the description. They do not indicate or imply that the devices or components referred to must have a specific orientation, be constructed, or operate in a specific orientation. Therefore, they should not be construed as limiting the present invention. Furthermore, terms such as "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0111] In the description of the present invention, it should be noted that, unless otherwise expressly specified or limited, the terms "connected" and "connection" should be understood in a broad sense. For example, they can refer to fixed connection, detachable connection, or integral connection; mechanical connection, electrical connection; direct connection, or indirect connection through an intermediary. Those skilled in the art will understand the specific meanings of the above terms in the present invention based on the specific circumstances.

[0112] 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.

[0113] References in this specification to "one embodiment" or "an embodiment" mean that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the present invention. Therefore, appearances of the phrases "one embodiment" or "an embodiment" in various places throughout this specification do not necessarily refer to the same embodiment.

[0114] Although the embodiments disclosed above are for facilitating understanding of the present invention, the contents described are merely embodiments adopted for facilitating understanding of the present invention and are not intended to limit the present invention. Any person skilled in the art of the present invention may make any modifications and changes in the form and details of the implementation without departing from the spirit and scope of the present invention. However, the scope of patent protection of the present invention shall still be subject to the scope defined by the appended claims.

Claims

1. A method for determining the in-situ limit mining depth of oil shale, characterized in that: include: Based on the oil shale samples in the in-situ area of ​​the oil shale to be evaluated, the permeability at different depths is measured; A pyrolysis experiment is performed on the oil shale sample to obtain the composition of each pseudo-product and the temperature-dependent component of each pseudo-product. Based on this, a pre-constructed multi-step overall reaction model based on kerogen pyrolysis is fitted to obtain the fitted model coefficients and reaction kinetic parameters; Predicting the formation temperature field formed by the heating conditions of the current formation due to the injection of high-temperature fluid, and based on this, combining the permeability at different depths, the model coefficients and the reaction kinetic parameters, predicting the production change curve; A profit prediction model related to the in-situ area of ​​the oil shale to be evaluated is established, and the limit mining depth when the profit value is zero is obtained from the production change curve.

2. The method according to claim 1, characterized in that The steps of performing a pyrolysis experiment on the oil shale sample to obtain the composition of each pseudo-product and the temperature-dependent components of each pseudo-product, and fitting a pre-constructed multi-step overall reaction model based on kerogen pyrolysis to obtain fitted model coefficients and reaction kinetic parameters include: Carry out heating pyrolysis experiments at a preset heating rate and under different pressure conditions to record the composition of each pseudo-product and the changes in the composition of each pseudo-product with temperature; The multi-step overall reaction model based on kerogen pyrolysis is established, and the multi-step overall reaction model is: Where m represents the total number of pseudo-products, X1, X2…X i …X m represents the pseudo-products of the 1st, 2nd…i…mth reactions, k1, k2…k i …k m Represents the 1st, 2nd…i…mth reaction formula, represents the model coefficient matrix; An error function is established between the experimental measurement values ​​and theoretical values ​​of the composition of each pseudo-product and the components of each pseudo-product that change with temperature, so as to solve the error function based on the experimentally measured component content of each pseudo-product that changes with temperature and the theoretical value of the component content of each fitting under corresponding conditions that changes with temperature, and obtain the model coefficients and reaction kinetic parameters, wherein the reaction kinetic parameters include but are not limited to the pre-exponential factor and activation energy.

3. The method according to claim 2, characterized in that The error function is expressed as follows: F(E i ,A i ,a i,j )=∑(X exp -X cal ) 2 Among them, F represents the objective function, E i represents the activation energy parameter of the i-th reaction, a i,j Represents the elements of the model coefficient matrix, A i represents the pre-exponential factor parameter of the i-th reaction, X exp Indicates the theoretical value of component content, X cal An experimentally measured value representing the amount of a component.

4. The method according to any one of claims 1 to 3, characterized in that The step of predicting the formation temperature field formed by the heating condition of the current formation based on the injection of high-temperature fluid includes: A formation temperature field prediction model is established to obtain the distribution characteristics of the formation temperature field under the well pattern heating condition. In the process of constructing the formation temperature field prediction model, the temperature fields generated by the electric heaters in different horizontal wells are considered and superimposed calculations are performed, including: Considering the seepage of high-temperature fluid in the oil shale formation, the high-temperature fluid carries heat and transfers and exchanges heat with the rock system in the form of conduction and convection. The governing equation is: Among them, F e represents the energy change function at different positions in the formation, t represents time, represents porosity, j represents the sequence number of different phase fluids, ρ j represents the density of the j-th phase fluid, S j represents the fluid saturation of the j-th phase fluid, u j represents the seepage velocity of the j-th phase fluid, U j represents the internal energy of the j-th phase fluid, H j represents the enthalpy of the j-th phase fluid, T represents the temperature, represents the temperature gradient, ρ s represents the density of kerogen, c s represents the specific heat capacity of kerogen, k represents the thermal conductivity, represents the well injection flow rate, q H Represents fluid energy.

5. The method according to any one of claims 1 to 4, characterized in that The step of predicting the production change curve of each hydrocarbon component in the in-situ area of ​​the oil shale to be evaluated includes: Based on the solved model coefficients and reaction kinetic parameters, the pyrolysis process under the actual well pattern heating conditions is simulated; Using the principle of mass conservation, the mass conservation equations for different pseudo-product components are established; Based on the mass conservation equation of the different pseudo-product components, combined with the permeability of the oil shale at different depths, the solved pyrolysis process, and the predicted formation temperature field distribution characteristics, the mass conservation equation is solved to obtain the production change curve in the in-situ area of ​​the oil shale to be evaluated under a given well pattern, given formation heating conditions and given depth conditions.

6. The method according to claim 5, characterized in that The mass conservation equations of the different pseudo-product components are expressed using the following expressions: Among them, F i represents the mass of the ith pseudo-product, t represents the time, represents porosity, j represents the sequence number of different phase fluids, ξ j represents the molar density of the j-phase fluid, ξ j =p j / ZRT, Z represents the gas compressibility coefficient, R represents the constant, T represents the temperature, p j represents the pressure of the j-phase fluid, X ij represents the mole fraction of the i-th pseudo-product component in the j-th phase fluid, u j represents the seepage velocity of the j-phase fluid, K represents the rock permeability, k rj represents the relative permeability of the j-phase fluid, μ j represents the viscosity of the j-phase fluid, represents the pressure gradient of the j-phase fluid, r k represents the reaction rate of the kth chemical reaction in the multi-step overall reaction model, v ij,k represents the coefficient of the i-th pseudo-product component in the j-th phase fluid in the k-th chemical reaction, Indicates the well injection rate.

7. The method according to claim 5 or 6, characterized in that The step of establishing a profit prediction model related to the oil shale in-situ area to be evaluated and obtaining the limit mining depth when the profit value is zero from the production change curve includes: According to the oil shale permeability at different depths, draw the production change curve under different depth conditions; According to the production change curves under different depth conditions, the profit value curve that changes with depth is fitted using the profit prediction model, so as to obtain the well depth when the profit value is zero, which is recorded as the limit mining depth.

8. The method according to claim 7, characterized in that The revenue prediction model is expressed using the following expression: Ci=Qi×Po Co=(P drl ·N w +P op ·T0+C dv ) P drl =P fix +P cph ·H N w =N ht +N pd ·b Among them, NPV represents the profit value, Ci represents the annual profit, Co represents the annual expenditure, r represents the interest rate, i represents the benchmark rate of return, N ht Number of heating wells, N pd represents the number of production wells, β represents the drilling cost ratio of production wells to heating wells, P drl represents the single well drilling cost, N w represents the well index, T0 represents the mining time, n represents the sequence number of the mining time, Qi represents the oil production, Po represents the crude oil price, C dv represents fixed investment in equipment, P op represents the operating cost, P fix represents the fixed cost of drilling a single well, P cph represents the drilling cost per meter, and H represents the well depth.

9. A system for determining the in-situ limit mining depth of oil shale, characterized in that: The system is used to implement the method according to any one of claims 1 to 8, and the system includes: a permeability measurement module configured to measure permeability at different depths based on oil shale samples from an in-situ area of ​​the oil shale to be evaluated; a reaction parameter fitting module configured to perform a pyrolysis experiment on the oil shale sample to obtain the composition of each pseudo-product and the temperature-dependent components of each pseudo-product, and based on this, fit a pre-constructed multi-step overall reaction model based on kerogen pyrolysis to obtain fitted model coefficients and reaction kinetic parameters; a production calculation module configured to predict a formation temperature field formed by heating conditions in the current formation due to high-temperature fluid injection, and based on this, predict a production change curve in combination with the permeability at different depths, the model coefficients, and the reaction kinetic parameters; A mining depth generation module is configured to establish a profit prediction model related to the oil shale in-situ area to be evaluated, and obtain the limit mining depth when the profit value is zero from the production change curve.

10. The system according to claim 9, characterized in that The output solution module includes: a temperature field prediction unit configured to predict a formation temperature field formed by heating conditions in a current formation based on injection of a high-temperature fluid; a pyrolysis process calculation unit configured to simulate the pyrolysis process under actual well pattern heating conditions based on the solved model coefficients and reaction kinetic parameters; a mass equation building unit configured to establish mass conservation equations for different pseudo-product components using the mass conservation principle; A production curve generating unit is configured to solve the mass conservation equation based on the mass conservation equation of the different pseudo-product components, combined with the oil shale permeability at different depths, the solved pyrolysis process, and the predicted formation temperature field distribution characteristics, so as to obtain the production change curve in the in-situ area of ​​the oil shale to be evaluated under the given well pattern mode, given formation heating conditions and given depth conditions.

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