CN113464129A - Method and device for calculating average formation pressure of coal bed gas reservoir - Google Patents

Method and device for calculating average formation pressure of coal bed gas reservoir Download PDF

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CN113464129A
CN113464129A CN202110887725.7A CN202110887725A CN113464129A CN 113464129 A CN113464129 A CN 113464129A CN 202110887725 A CN202110887725 A CN 202110887725A CN 113464129 A CN113464129 A CN 113464129A
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CN113464129B (en
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石军太
张龙龙
李文斌
贾焰然
李星浩
石浩田
徐涛
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China University of Petroleum Beijing
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Abstract

According to the method and the device for calculating the average formation pressure of the coal bed gas reservoir, the basic parameters of the coal bed, the accumulated water yield of the coal bed gas well and the accumulated gas yield are counted, the average formation pressure of the coal bed gas reservoir is calculated by using the basic parameters, the accumulated water yield and the accumulated gas yield, and the used parameters are easy to obtain, so that the difficulty, the cost and the like of calculating the average formation pressure are reduced. In addition, the formation pressure and the critical desorption pressure are obtained, whether the formation pressure is greater than the critical desorption pressure or not is judged, the coal bed gas reservoir is determined to be in an early drainage stage or a gas desorption stage, the average formation pressure of the coal bed gas reservoir is calculated in different calculation modes according to different stages, and in the development process of the coal bed gas, the influence caused by dissolved gas, stress sensitivity and matrix shrinkage is considered, so that the average formation pressure of the coal bed gas reservoir can be calculated more accurately, and accurate reference is provided for judging the residual reserve of the coal bed gas and the interwell interference condition.

Description

Method and device for calculating average formation pressure of coal bed gas reservoir
Technical Field
The invention relates to a coal bed gas exploration and development technology, in particular to a method and a device for calculating average formation pressure of a coal bed gas reservoir by considering dissolved gas, stress sensitivity and matrix shrinkage.
Background
The coal bed gas is self-storage natural gas which is adsorbed or exists in a free state in a coal bed and a solid rock through biochemical pyrolysis in a coal forming process, and belongs to unconventional natural gas. The development of the coal bed gas is beneficial to zero discharge of carbon dioxide, the coal bed gas which is the root source of coal mine gas explosion accidents is changed into resources, and the problem of resource shortage is solved.
Because the pore diameter of the coal bed matrix is small, the quantity of the coal bed matrix is large, the inner surface of the coal bed matrix adsorbs a large amount of natural gas to cause the interaction of rock and gas, most of the existing coal bed gas material balance equation methods do not consider the influence of dissolved gas and free gas and the difference between the original formation pressure and the critical desorption pressure, and the average formation pressure calculated according to the coal bed gas material balance equation method does not consider the factors.
The existing coal bed gas material balance equation method has poor adaptability, so that the average stratum pressure error calculated according to the method is large. Especially for deep coal bed gas reservoirs with high original formation pressure, low reservoir temperature, low critical desorption pressure and small Langmuir volume, if the influence of free gas, dissolved gas and matrix shrinkage is neglected, the formation pressure of the coal bed gas reservoir will deviate from the actual value seriously.
Disclosure of Invention
The application provides a method and a device for calculating the average formation pressure of a coal bed gas reservoir, which solve the problem of calculating the average formation pressure of the coal bed gas reservoir under the condition of considering the influence of dissolved gas and free gas and the difference between the original formation pressure and the critical desorption pressure.
In one aspect, the present application provides a method for calculating an average formation pressure of a coal bed methane reservoir, including:
the method comprises the following steps of counting basic parameters of the coal bed gas reservoir, the daily accumulated water yield of the coal bed gas well and the accumulated gas yield, wherein the basic parameters comprise: langmuir volume, Langmuir pressure constant, virgin formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, virgin porosity, virgin water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane dissolution factor, formation water volume factor, standard pressure, standard temperature, deviation factor at standard pressure, and water invasion;
acquiring formation pressure and critical desorption pressure;
when the formation pressure is greater than or equal to the critical desorption pressure, calculating the basic parameters, the accumulated water yield and the accumulated gas yield by adopting a first calculation mode to obtain a first average formation pressure of the coal bed gas reservoir in an early drainage stage;
and when the formation pressure is smaller than the critical desorption pressure, calculating the basic parameters, the accumulated water yield and the accumulated gas yield by adopting a second calculation mode to obtain a second average formation pressure of the coal bed gas reservoir in a gas desorption stage.
Optionally, the calculating the basic parameter, the accumulated water yield and the accumulated gas yield by using a first calculation method to obtain a first average formation pressure of the coal bed methane reservoir at an early drainage stage includes:
calculating the first average formation pressure by an iterative process of:
calculating an M value, a free gas original geological reserve, a solution gas original geological reserve and an original pore volume from the reservoir temperature, the standard pressure, a deviation coefficient at the standard pressure, the original water saturation, the original formation pressure, a solubility coefficient for the methane, the single well control area, the coal seam thickness and the original porosity;
fitting according to the gas relative density and the reservoir temperature to obtain a relational expression of pressure and a deviation coefficient;
obtaining a deviation coefficient corresponding to the initial value of the first average lamination pressure according to the initial value of the first average lamination pressure and the relation between the pressure and the deviation coefficient, wherein the initial value of the first average lamination pressure used in the k-th iteration is a calculated value of the first average lamination pressure obtained in the k-1-th iteration;
calculating coefficients a, b and c according to the M value, the original free gas geological reserve, the original solution gas geological reserve, the original pore volume, the current value of the first average formation pressure, the accumulated gas production, the accumulated water production, the original water saturation, the formation compressibility, the formation water volume coefficient and the water invasion;
substituting the coefficients a, b, c into equation (1) to obtain a calculated value of the first average laminate pressure, where equation (1) is:
Figure BDA0003194809920000021
wherein the content of the first and second substances,
Figure BDA0003194809920000031
calculating a first average formation pressure for a kth iteration, wherein k is an iteration number;
when the difference value between the calculated value of the first average lamination pressure obtained by the kth iteration and the initial value of the first average lamination pressure is smaller than a preset first absolute error, ending the iteration process, and taking the calculated value of the first average lamination pressure obtained by the kth iteration as a final value of the first average lamination pressure;
and when the difference value between the calculated value of the first average lamination pressure obtained by the kth iteration and the initial value of the first average lamination pressure is not smaller than the first absolute error, adding 1 to k, and entering the (k + 1) th iteration.
Optionally, calculating an M value, a free gas original geological reserve, a solution gas original geological reserve and an original pore volume from the reservoir temperature, the standard pressure, a deviation coefficient at the standard pressure, the original water saturation, the original formation pressure, a solubility coefficient of the methane, the single well control area, the coal seam thickness and the original porosity comprises:
calculating the M value, the free gas original geological reserve, the solution gas original geological reserve and the original pore volume using equations (2) - (5):
Figure BDA0003194809920000032
Figure BDA0003194809920000033
Gsi＝VpiSwiCspi (4)
Vpi＝Ahφi (5)
wherein Z isscIs the coefficient of deviation at standard pressure, TscIs a standard temperature, pscIs standard pressure, T is coal reservoir temperature, GfiFor original geological reserves of free gas, VpiTo the original pore volume, SwiIs the original water saturation, piIs the original formation pressure, ZiIs the coefficient of deviation at the original formation pressure, CsIs the solubility coefficient of methane, GsiFor the original geological reserves of solution gas, A is the single well control area, phiiAnd h is the thickness of the coal bed.
Optionally, the calculating coefficients a, b, and c according to the M value, the original free gas geological reserve, the original solution gas geological reserve, the original pore volume, the current value of the first average formation pressure, the cumulative gas production, the cumulative water production, the original water saturation, the formation compressibility, the formation water volume coefficient, and the water invasion amount includes:
the coefficients a, b, c are calculated using equations (6) to (8):
Figure BDA0003194809920000041
Figure BDA0003194809920000042
Figure BDA0003194809920000043
wherein k is the number of iterations,
Figure BDA0003194809920000044
the deviation coefficient, C, corresponding to the mean formation pressurepIs the coefficient of pore compressibility, CwIs the formation water compression coefficient, WeWater invasion, WpTo accumulate water production, GpTo accumulate gas production, BwIs the formation water volume factor.
Optionally, the calculating the basic parameter, the accumulated water yield and the accumulated gas yield by using a second calculation method to obtain a second average formation pressure of the coal bed gas reservoir in the gas desorption stage includes:
calculating said M value, said free gas original geological reserve, said solution gas original geological reserve and said original pore volume using equations (2) - (5):
calculating to obtain the original geological reserve G of the adsorbed gas by adopting a formula (9)aiEquation (9) is as follows:
Figure BDA0003194809920000045
wherein，GaiFor adsorbing gas original geological reserves, VLIs the Langmuir volume, b is the Langmuir pressure constant, pdIs the critical desorption pressure.
Performing an iterative operation on equation (10) to obtain the second average formation pressure, where equation (10) is as follows:
Figure BDA0003194809920000046
wherein, CaThe shrinkage factor of the coal matrix.
Optionally, the performing an iterative operation on the formula (10) to obtain the second average formation pressure includes:
the iterative manner of determining equation (10) is:
Figure BDA0003194809920000051
wherein the F function is:
Figure BDA0003194809920000052
derivation is performed on both sides of equation (12) to obtain equation (13):
Figure BDA0003194809920000053
obtaining a deviation coefficient corresponding to the initial value of the second average lamination pressure according to the initial value of the second average lamination pressure and the relation between the pressure and the deviation coefficient, wherein the initial value of the second average lamination pressure used in the kth iteration is a calculated value of the second average lamination pressure obtained in the kth-1 th iteration;
substituting the deviation coefficient corresponding to the initial value of the second average lamination pressure into the formulas (12) and (13) to calculate the value of the F function and the derivative value F' of the F function;
substituting the F function and the reciprocal value F' of the F function into the formula (11) to carry out Newton iteration to obtain a calculated value of the second average lamination pressure obtained by the k-th iteration;
when the difference value between the calculated value of the second average lamination pressure obtained by the kth iteration and the initial value of the second average lamination pressure is smaller than a preset second absolute error, ending the iteration process, and taking the calculated value of the second average lamination pressure obtained by the kth iteration as a final value of the second average lamination pressure;
and when the difference value between the calculated value of the second average lamination pressure obtained by the kth iteration and the initial value of the second average lamination pressure is not less than the second absolute error, adding 1 to k, and entering the kth +1 iteration.
In a second aspect, the present application provides a coal bed methane reservoir average formation pressure calculation apparatus, including:
the statistical module is used for counting basic parameters of the coal bed gas reservoir, the daily accumulated water yield and the daily accumulated gas yield of the coal bed gas well, and the basic parameters comprise: langmuir volume, Langmuir pressure constant, virgin formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, virgin porosity, virgin water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane dissolution factor, formation water volume factor, standard pressure, standard temperature, deviation factor at standard pressure, and water invasion;
the acquisition module is used for acquiring formation pressure and critical desorption pressure;
the first calculation module is used for calculating the basic parameters, the accumulated water yield and the accumulated gas yield in a first calculation mode to obtain a first average formation pressure of the coal bed gas reservoir in an early drainage stage when the formation pressure is greater than or equal to the critical desorption pressure;
and the second calculation module is used for calculating the basic parameters, the accumulated water yield and the accumulated gas yield in a second calculation mode when the formation pressure is smaller than the critical desorption pressure to obtain a second average formation pressure of the coal bed gas reservoir in a gas desorption stage.
In a third aspect, the present invention provides an electronic device comprising: at least one processor and memory;
the memory stores computer-executable instructions;
the at least one processor executes the memory-stored computer-executable instructions, which the at least one processor executes cause the at least one processor to perform the method according to the first aspect of the invention.
In a fourth aspect, the present invention provides a computer readable storage medium having stored thereon computer executable instructions for performing the method according to the first aspect of the present invention when executed by a processor.
In a fifth aspect, the invention provides a computer program product comprising a computer program which, when executed by a processor, performs the method according to the first aspect of the invention.
According to the method and the device for calculating the average formation pressure of the coal bed gas reservoir, the average formation pressure of the coal bed gas reservoir is calculated by counting the basic parameters of the coal bed gas reservoir, the accumulated water yield of the coal bed gas well and the accumulated gas yield, and the basic parameters, the accumulated water yield and the accumulated gas yield are easy to obtain, so that the difficulty, the cost and the like of calculating the average formation pressure are reduced. In addition, the formation pressure and the critical desorption pressure are obtained, the first average formation pressure of the coalbed methane in the early drainage stage is calculated by adopting a first calculation mode through judging whether the formation pressure is greater than or equal to the critical desorption pressure or not, the second average formation pressure of the coalbed methane in the gas desorption stage is calculated by adopting a second calculation mode when the formation pressure is less than the critical desorption pressure, and in the coalbed methane development process, the influences caused by dissolved gas, stress sensitivity and matrix shrinkage are considered, so that the average formation pressure of the coalbed methane reservoir can be calculated more accurately, and accurate reference is provided for judging the residual reserve volume of the coalbed methane and the interference condition between wells.
Drawings
The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the present application and together with the description, serve to explain the principles of the application.
Fig. 1 is a schematic flow chart of a method for calculating the average formation pressure of a coalbed methane reservoir according to an embodiment of the present invention.
FIG. 2 is a graph of the fit of formation pressure to deviation coefficients.
FIG. 3 is a graph of data of cumulative water production and cumulative gas production at an early drainage stage of a coal bed methane reservoir.
FIG. 4 is a graph of average formation pressure for a coalbed methane reservoir at an early drainage stage.
FIG. 5 is a diagram of data of cumulative water production and cumulative gas production at a gas desorption stage of a coalbed methane reservoir.
FIG. 6 is a graph of average formation pressure for a coalbed methane reservoir during a gas desorption phase.
Fig. 7 is a schematic structural diagram of an apparatus for calculating an average formation pressure of a coalbed methane reservoir according to a third embodiment of the present invention.
Fig. 8 is a schematic structural diagram of an electronic device according to a fourth embodiment of the present invention.
With the above figures, there are shown specific embodiments of the present application, which will be described in more detail below. These drawings and written description are not intended to limit the scope of the inventive concepts in any manner, but rather to illustrate the inventive concepts to those skilled in the art by reference to specific embodiments.
Detailed Description
Reference will now be made in detail to the exemplary embodiments, examples of which are illustrated in the accompanying drawings. When the following description refers to the accompanying drawings, like numbers in different drawings represent the same or similar elements unless otherwise indicated. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with the present application. Rather, they are merely examples of apparatus and methods consistent with certain aspects of the present application, as detailed in the appended claims.
The terms referred to in this application are explained first:
critical desorption pressure: it means a pressure corresponding to when desorption and adsorption reach equilibrium, that is, a pressure at which a pressure decrease causes desorption of gas adsorbed on the surface of the coal micropores to start. Theoretically, when the reservoir pressure is reduced to be lower than the critical desorption pressure, the gas adsorbed in the pores of the coal begins to desorb and moves towards the fracture, and flows from the fracture to the well bore under the action of the pressure difference. At present, most of coal bed gas exploitation is based on the principle, and the aim of gas exploitation is achieved by draining water and reducing pressure. The critical desorption pressure is given in MPa, usually by the symbol pdAnd (4) showing.
Free gas: namely free gas, which refers to natural gas stored in pores or fractures of a coal seam and can freely move, and the amount of free gas in the coal seam depends on the size of the gas storage pores and fracture spaces, temperature, pressure, gas compressibility and other factors.
Dissolved gas: natural gas present in dissolved state in crude oil or water.
Deviation coefficient: it refers to the deviation in volume of the actual gas after compression and the ideal gas after compression at the same pressure, and the deviation coefficient is a dimensionless quantity and is generally represented by the symbol Z.
The method for calculating the average formation pressure of the existing coal bed gas reservoir does not consider the influence of dissolved gas and free gas and the difference between the original formation pressure and the critical desorption pressure, particularly, for a deep coal bed gas reservoir with higher original formation pressure, lower reservoir temperature, lower critical desorption pressure and smaller Langmuir volume, if the influence of free gas, dissolved gas and matrix shrinkage is neglected, the average formation pressure of the coal bed gas reservoir generates serious deviation, and the average formation pressure is used as a main influence factor of coal bed gas exploitation, so that the judgment of the residual reserve volume of the coal bed gas and the interference situation between wells also generates serious deviation, therefore, a method for calculating the average formation pressure of the coal bed gas reservoir considering the dissolved gas, the stress sensitivity and the matrix shrinkage is necessary to be established.
Therefore, the method for calculating the average formation pressure of the coalbed methane reservoir considering the dissolved gas, the stress sensitivity and the matrix shrinkage can be used for calculating the average formation pressure of the coalbed methane reservoir at each stage by considering the difference between the original formation pressure and the critical desorption pressure and carrying out iterative calculation based on the basic parameters and the production data of the reservoir, and the parameters are easy to obtain and simple and reliable.
The following describes the technical solutions of the present application and how to solve the above technical problems with specific embodiments. The following several specific embodiments may be combined with each other, and details of the same or similar concepts or processes may not be repeated in some embodiments. Embodiments of the present application will be described below with reference to the accompanying drawings.
Fig. 1 is a schematic flow chart of a method for calculating an average formation pressure of a coal bed methane reservoir according to an embodiment of the present invention, where the method may be performed by a device for calculating an average formation pressure of a coal bed methane reservoir, where the device may be a computer, a tablet computer, a mobile phone, and the like, and the method may include the following steps.
Step 101: and (5) counting the basic parameters of the coal bed gas reservoir, the accumulated water yield of the coal bed gas well and the accumulated gas yield.
The basic parameters of the coalbed methane reservoir comprise: langmuir volume, Langmuir pressure constant, virgin formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, virgin porosity, virgin water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane dissolution factor, formation water volume factor, standard pressure, standard temperature, deviation factor at standard pressure, and water invasion.
And counting basic parameters of the coal bed gas reservoir and storing the basic parameters for calculating the average formation pressure of the subsequent coal bed gas reservoir, wherein the basic parameters can be stored in a form of a table.
Watch 1
Parameter(s) Value taking Unit of
Langmuir volume VL 14 m3/m3
Langmuir pressure constant b 0.278 MPa-1
Pressure p of the original formationi 9.95 MPa
Critical desorption pressure pd 7.5 MPa
Single well control area a 100000 m2
Thickness h of coal seam 21.15 m
Reservoir temperature T 313.15 K
Relative density of gas gammag 0.6 Dimensionless
Original porosity phii 0.04 Decimal fraction
Original water saturation Swi 0.95 Decimal fraction
Coefficient of shrinkage of coal matrix Ca 0.019 Dimensionless
Formation water compressibility factor Cw 0.000425 Dimensionless
Coefficient of pore compression Cp 0.01087 Dimensionless
Coefficient of dissolution C of methanes 0.044 MPa-1
Volume coefficient of formation water Bw 1.0 m3/sm3
Standard pressure psc 0.101325 MPa
Standard temperature Tsc 293.15 K
Coefficient of deviation Z at standard pressuresc 1 Dimensionless
Deviation coefficient Z under virgin formation pressurei 0.86548377 Dimensionless
Water intrusion We 0 m3
It should be understood that the values of the basic parameters in table one are only for illustration and are not limiting.
Step 102: and acquiring the formation pressure and the critical desorption pressure.
When the formation pressure is greater than or equal to the critical desorption pressure, the coalbed methane reservoir is in an early drainage stage. And when the formation pressure is less than the critical desorption pressure, the coal bed gas reservoir is in a gas desorption stage.
The early drainage stage adopts a first calculation mode to calculate the average formation pressure of the coal bed gas reservoir, and the gas desorption stage adopts a second calculation mode to calculate the average formation pressure of the coal bed gas reservoir.
Step 103: and when the formation pressure is greater than or equal to the critical desorption pressure, calculating the basic parameters, the accumulated water yield and the accumulated gas yield by adopting a first calculation mode to obtain a first average formation pressure of the coal bed gas reservoir in the early drainage stage.
An exemplary first average formation pressure of a coalbed methane reservoir at an early drainage stage may be calculated by an iterative process as follows:
(1) and calculating the M value, the original geological reserve of the free gas, the original geological reserve of the dissolved gas and the original pore volume according to the reservoir temperature, the standard pressure, the deviation coefficient under the standard pressure, the original water saturation, the original formation pressure, the dissolution coefficient of methane, the single well control area, the coal bed thickness and the original porosity.
Calculating the M value and the original geological reserve G of the free gas according to the following formulafiOriginal geological reserve G of solution gassiAnd original pore volume Vpi：
Figure BDA0003194809920000101
Figure BDA0003194809920000102
Gsi＝VpiSwiCspi (4)
Vpi＝Ahφi (5)
Wherein Z isscIs the coefficient of deviation at standard pressure, TscIs a standard temperature, pscIs standard pressure, T is coal reservoir temperature, GfiFor original geological reserves of free gas, VpiTo the original pore volume, SwiIs the original water saturation, piIs the original formation pressure, ZiIs the coefficient of deviation at the original formation pressure, CsIs the solubility coefficient of methane, GsiFor the original geological reserves of solution gas, A is the single well control area, phiiAnd h is the thickness of the coal bed.
Taking the values of the parameters shown in Table I as an example, the deviation coefficient Z under the standard pressurescHas a value of 1, standard temperature TscHas a value of 293.15K, standard pressure pscHas a value of 0.101325MPa, reservoir temperature TIs 313.15K, and substituting the above parameters into equation (1) yields an M value of 9.2389. Then the original water saturation S is measuredwiHas a value of 0.95, the original formation pressure piHas a value of 9.95MPa and a deviation coefficient Z under the original formation pressureiValue of 0.86548377, solubility coefficient of methane CsHas a value of 0.044MPa-1The value of the single well control area A is 100000m2The value of the coal seam thickness h is 21.15M, M is substituted into the formulas (2), (3) and (4) to obtain the original pore volume V of the coal seam gas reservoirpiIs 105750.00m3Original geological reserve of free gas GfiIs 561609.96m3Original geological reserve G of solution gassiIs 43982.48m3。
(2) And fitting according to the gas relative density and the reservoir temperature to obtain a relational expression of the pressure and the deviation coefficient.
Illustratively, the Dranchuk-Abou-Kassem method is applied to obtain the deviation coefficient at any formation pressure according to the relative gas density and the reservoir temperature, and in order to make the calculation process simpler, polynomial fitting is performed, and the fitting result is shown in FIG. 2, R21 means that the polynomial fit works well. The fitting results were as follows:
Figure BDA0003194809920000111
wherein k is the number of iterations,
Figure BDA0003194809920000112
is the deviation factor corresponding to the average formation pressure,
Figure BDA0003194809920000113
the first average laminate pressure obtained for the kth iteration.
The polynomial is used to calculate a deviation factor corresponding to the average formation pressure.
As a possible implementation manner, the deviation coefficient under any formation pressure can be obtained by the AGA8-92DC method, the Mahmoud method and the like, and the description of applying the Dranchuk-Abou-Kassem method in the embodiment is only an example and is not limiting.
(3) And obtaining a deviation coefficient corresponding to the initial value of the first average lamination pressure according to the initial value of the first average lamination pressure and a relation between the pressure and the deviation coefficient, wherein the initial value of the first average lamination pressure used in the kth iteration is a calculated value of the first average lamination pressure obtained in the kth-1 th iteration.
Illustratively, the coal bed gas reservoir is drained in an early stage, taking production data of 8-13 days in 2014 as an example, the bottom hole flowing pressure in the coal bed gas production is 2.98MPa, and the bottom hole flowing pressure is taken as an initial value of the average formation pressure
Figure BDA0003194809920000114
Calculating the deviation coefficient corresponding to the initial value according to the relation between the pressure and the deviation coefficient
Figure BDA0003194809920000115
Is 0.9523.
The initial value of the first average formation pressure used in the 1 st iteration is the calculated value of the first average formation pressure obtained in the 0 th iteration, i.e. the bottom hole flow pressure is the initial value.
The initial value of the first average laminate pressure used in iteration 2 is the calculated value of the first average laminate pressure obtained in iteration 1.
As a possible implementation manner, the description of the initial value used in the iteration in this embodiment is only an example, and the number of iterations is not limited.
(4) Calculating coefficients a, b and c according to the M value, the original free gas geological reserve, the original solution gas geological reserve, the original pore volume, the current value of the first average formation pressure, the accumulated gas production, the accumulated water production, the original water saturation, the formation compressibility, the formation water volume coefficient and the water invasion;
the coefficients a, b, c are calculated according to the following formula:
Figure BDA0003194809920000116
Figure BDA0003194809920000121
Figure BDA0003194809920000122
wherein k is the number of iterations,
Figure BDA0003194809920000123
is a deviation coefficient corresponding to the average formation pressure, CpIs the coefficient of pore compressibility, CwIs the formation water compression coefficient, WeWater invasion, WpTo accumulate water production, GpTo accumulate gas production, BwIs the formation water volume factor.
For example, the cumulative water production and the cumulative gas production data of the coalbed methane reservoir in the early drainage stage are shown in FIG. 3, WpIndicating cumulative water production, GpRepresents the cumulative gas production, given the production data of 8 months and 13 days in 2014 as an example, Gp＝117469.06m3，Wp＝1367.92m3. The values of the parameters shown in Table I and the deviation coefficients corresponding to the initial values of the average formation pressure
Figure BDA0003194809920000124
Substituting equations (6) - (8) for 0.9523, a was calculated to have a value of 0.1097, b was calculated to have a value of-0.4398, and c was calculated to have a value of-4.6158.
(5) Substituting the coefficients a, b, c into equation (1) to obtain a calculated value of the first average laminate pressure, equation (1) being:
Figure BDA0003194809920000125
wherein the content of the first and second substances,
Figure BDA0003194809920000126
calculated value of first average formation pressure for k iteration, k being stackThe generation number.
And when the difference value between the calculated value of the first average lamination pressure obtained by the kth iteration and the initial value of the first average lamination pressure is smaller than a preset first absolute error, ending the iteration process, and taking the calculated value of the first average lamination pressure obtained by the kth iteration as the final value of the first average lamination pressure.
And when the difference value between the calculated value of the first average lamination pressure obtained by the kth iteration and the initial value of the first average lamination pressure is not smaller than the first absolute error, adding 1 to k, and entering the kth +1 iteration.
Illustratively, the values of a, b and c in the previous step are substituted into equation (1), and the first average laminate pressure obtained in the 1 st iteration is obtained
Figure BDA0003194809920000127
Has a value of 8.7935MPa, at this time
Figure BDA0003194809920000128
And initial value of average formation pressure
Figure BDA0003194809920000129
Is 5.8135MPa, the error is not less than the preset first absolute error of 0.001MPa, and the calculated value is
Figure BDA00031948099200001210
As an initial value, k is added by 1, and the pressure-to-deviation coefficient relation, formula (1) and formulas (6) to (8) are repeated, and the 2 nd iteration is entered.
The results of the iterative calculations are shown in Table two, the first average formation pressure obtained in iteration 2
Figure BDA00031948099200001211
Value of 8.5737MPa and the first average formation pressure obtained in iteration 1
Figure BDA00031948099200001212
The absolute error 0.2198MPa is not less than the preset first absolute error 0.001MPa, and the calculated value is
Figure BDA00031948099200001213
As an initial value, k is added by 1, and the pressure-to-deviation coefficient relation, formula (1) and formulas (6) to (8) are repeated, and the 3 rd iteration is entered. First average formation pressure from iteration 3
Figure BDA0003194809920000131
Value of 8.5806MPa and the first average formation pressure obtained in iteration 2
Figure BDA0003194809920000132
Is not less than 0.001MPa of the preset first absolute error, and calculating the value
Figure BDA0003194809920000133
As an initial value, k is added to 1, and the relationship of pressure and deviation coefficient, formula (1) and formulas (6) to (8) are repeated, and the 4 th iteration is entered. First average formation pressure from iteration 4
Figure BDA0003194809920000134
Value of 8.5804MPa and the first average formation pressure obtained in iteration 3
Figure BDA0003194809920000135
Absolute error of 0.0002MPa is less than the preset first absolute error of 0.001MPa, the iteration process is ended, and the first average formation pressure obtained by the 4 th iteration is used
Figure BDA0003194809920000136
The value of (A) is 8.5804MPa as the final value of the average formation pressure of the daily coalbed methane reservoir.
Watch two
Figure BDA0003194809920000137
Figure 4 is a graph of the average formation pressure of a coalbed methane reservoir at an early drainage stage,
Figure BDA0003194809920000138
to mean formation pressure, pwfFor bottom hole flowing pressure, the average formation pressure is always greater than the bottom hole flowing pressure, and the method is reflected to be high in accuracy.
Step 104: and when the formation pressure is less than the critical desorption pressure, calculating the basic parameters, the accumulated water yield and the accumulated gas yield by adopting a second calculation mode to obtain a second average formation pressure of the coal bed gas reservoir in the gas desorption stage.
An exemplary second average formation pressure of the coalbed methane at the gas desorption stage may be calculated by an iterative process as follows:
(1) the M value, free gas original geological reserve, solution gas original geological reserve and original pore volume are calculated using equations (2) - (5).
Taking the values of the parameters shown in Table I as an example, the deviation coefficient Z under the standard pressurescHas a value of 1, standard temperature TscHas a value of 293.15K, standard pressure pscThe value of (d) is 0.101325MPa, the value of the reservoir temperature T is 313.15K, and the values of M are 9.2389 by substituting the above parameters into the formula (2). Then the original water saturation S is measuredwiHas a value of 0.95, the original formation pressure piHas a value of 9.95MPa and a deviation coefficient Z under the original formation pressureiValue of 0.86548377, solubility coefficient of methane CsHas a value of 0.044MPa-1The value of the single well control area A is 100000m2The value of the coal seam thickness h is 21.15M, M is substituted into the formulas (3), (4) and (5) to obtain the original pore volume V of the coal seam gas reservoirpiIs 105750.00m3Original geological reserve of free gas GfiIs 561609.96m3Original geological reserve G of solution gassiIs 43982.48m3。
(2) Calculating to obtain the original geological reserve G of the adsorbed gas by adopting a formula (9)aiEquation (9) is as follows:
Figure BDA0003194809920000141
wherein G isaiFor adsorbing gas original geological reserves，VLIs the Langmuir volume, b is the Langmuir pressure constant, pdIs the critical desorption pressure.
Taking the values of the parameters shown in the table I as an example, the value of the single-well control area A is 100000m2The value of the coal seam thickness h is 21.15m, the Langmuir volume VLHas a value of 14m3/m3The Langmuir pressure constant b was 0.278MPa-1And critical desorption pressure pdThe value of (A) is 7.5MPa, and the original geological reserve G of the adsorbed gas is obtained by substituting the value into the formula (9)aiIs 20006756.76m3。
(3) And (3) carrying out iterative operation on the formula (10) to obtain a second average lamination pressure, wherein the formula (10) is as follows:
Figure BDA0003194809920000142
wherein, CaThe shrinkage factor of the coal matrix.
Optionally, performing an iterative operation on the formula (10) to obtain a second average formation pressure includes:
the iterative manner of determining equation (10) is:
Figure BDA0003194809920000143
wherein the F function is:
Figure BDA0003194809920000144
derivation is performed on both sides of equation (12) to obtain equation (13):
Figure BDA0003194809920000151
and obtaining a deviation coefficient corresponding to the initial value of the second average lamination pressure according to the initial value of the second average lamination pressure and the relation between the pressure and the deviation coefficient, wherein the initial value of the second average lamination pressure used in the kth iteration is a calculated value of the second average lamination pressure obtained in the kth-1 th iteration.
The deviation coefficient corresponding to the initial value of the second average laminate pressure is substituted into the equations (12) and (13) to calculate the value of the F function and the derivative value F' of the F function.
And substituting the F function and the derivative value F' of the F function into a formula (11) to carry out Newton iteration to obtain a calculated value of the second average lamination pressure obtained by the kth iteration.
And when the difference value between the calculated value of the second average lamination pressure obtained by the kth iteration and the initial value of the second average lamination pressure is smaller than a preset second absolute error, ending the iteration process, and taking the calculated value of the second average lamination pressure obtained by the kth iteration as the final value of the second average lamination pressure.
And when the difference value between the calculated value of the second average lamination pressure obtained by the kth iteration and the initial value of the second average lamination pressure is not less than the second absolute error, adding 1 to k, and entering the kth +1 iteration.
Illustratively, the cumulative water production and the cumulative gas production data for the coalbed methane reservoir during the gas desorption stage are shown in the example of fig. 5, WpIndicating cumulative water production, GpRepresents the cumulative gas production, as exemplified by the production data of 12 months and 23 days in 2015Gp＝1758207.89m3，Wp＝5545.52m3The bottom hole flowing pressure is 2.35MPa, and the bottom hole flowing pressure is taken as the initial value of the average formation pressure
Figure BDA0003194809920000152
Calculating the deviation coefficient corresponding to the initial value according to the relation between the pressure and the deviation coefficient
Figure BDA0003194809920000153
Is 0.9618.
Illustratively, the cumulative water production WpCumulative gas production GpInitial value of average formation pressure
Figure BDA0003194809920000154
It corresponds toCoefficient of deviation
Figure BDA0003194809920000155
Substituting the values of the parameters shown in the sum table I into the formulas (12) and (13), and calculating to obtain the values
Figure BDA0003194809920000156
Will average the initial value of the formation pressure
Figure BDA0003194809920000157
Calculated to obtain
Figure BDA0003194809920000158
Value of (A) and
Figure BDA0003194809920000159
is substituted into equation (11), and the 1 st iteration yields a second average laminate pressure
Figure BDA00031948099200001510
Has a value of 4.6737MPa, at this time
Figure BDA00031948099200001511
And initial value of average formation pressure
Figure BDA00031948099200001512
Is 2.3237MPa, the error is not less than the second absolute error of 0.001MPa, and the value is calculated
Figure BDA00031948099200001513
As an initial value, k is added to 1, and the pressure-to-deviation coefficient relation and equations (11) to (13) are repeated, and iteration 2 is entered.
The results of the iterative calculations are shown in Table three, with the second average formation pressure from iteration 2
Figure BDA00031948099200001514
Value of 5.8210MPa and the second average formation pressure obtained in iteration 1
Figure BDA00031948099200001515
Is not less than a preset second absolute error of 0.001MPa, calculating the value
Figure BDA0003194809920000161
As an initial value, k is added to 1, and the pressure-to-deviation coefficient relation and equations (11) to (13) are repeated, and the 3 rd iteration is performed. Second average formation pressure from iteration 3
Figure BDA0003194809920000162
Value of 5.9692MPa and the second average formation pressure obtained in the 2 nd iteration
Figure BDA0003194809920000163
Is not less than a preset second absolute error of 0.001MPa, calculating the value
Figure BDA0003194809920000164
As an initial value, k is added to 1, and the pressure-to-deviation coefficient relation and equations (11) to (13) are repeated, and the 4 th iteration is entered. Second average formation pressure from iteration 4
Figure BDA0003194809920000165
Value of 5.9706MPa and the second average formation pressure obtained in iteration 3
Figure BDA0003194809920000166
Is not less than 0.0014MPa, and the calculated value is not less than 0.001MPa
Figure BDA0003194809920000167
As an initial value, k is added by 1, and the pressure-to-deviation coefficient relation and equations (11) to (13) are repeated, and the 5 th iteration is entered. Second average formation pressure from iteration 5
Figure BDA0003194809920000168
Is 5.9706MPa and laminated with the second average obtained in the 4 th iterationForce of
Figure BDA0003194809920000169
Is less than a preset second absolute error of 0.001MPa, the iteration process is ended, and a second average formation pressure obtained by the 5 th iteration is obtained
Figure BDA00031948099200001610
The value of (A) is 5.9706MPa as the final value of the average formation pressure of the daily coalbed methane reservoir.
Watch III
Figure BDA00031948099200001611
Figure 6 is a graph of the average formation pressure of a coalbed methane reservoir during a gas desorption phase,
Figure BDA00031948099200001612
to mean formation pressure, pwfFor bottom hole flowing pressure, the average formation pressure is always greater than the bottom hole flowing pressure, and the method is reflected to be high in accuracy.
In the embodiment, the basic parameters of the coal bed gas reservoir, the accumulated water yield of the coal bed gas well and the accumulated gas yield are counted, the average formation pressure of the coal bed gas reservoir is calculated by using the basic parameters, the accumulated water yield and the accumulated gas yield, the basic parameters, the accumulated water yield and the accumulated gas yield are easy to obtain, and therefore the difficulty, the cost and the like of average formation pressure calculation are reduced. In addition, the formation pressure and the critical desorption pressure are obtained, the first average formation pressure of the coalbed methane in the early drainage stage is calculated by adopting a first calculation mode through judging whether the formation pressure is greater than or equal to the critical desorption pressure or not, the second average formation pressure of the coalbed methane in the gas desorption stage is calculated by adopting a second calculation mode when the formation pressure is less than the critical desorption pressure, and in the coalbed methane development process, the influences caused by dissolved gas, stress sensitivity and matrix shrinkage are considered, so that the average formation pressure of the coalbed methane reservoir can be calculated more accurately, and accurate reference is provided for judging the residual reserve volume of the coalbed methane and the interference condition between wells.
Fig. 7 is a schematic structural diagram of an apparatus for calculating an average formation pressure of a coalbed methane reservoir according to a third embodiment of the present invention, where the apparatus 100 includes a statistics module 11, an obtaining module 12, a first calculation module 13, and a second calculation module 14.
The statistic module 11 is used for calculating basic parameters of the coal bed gas reservoir, the daily accumulated water yield of the coal bed gas well and the accumulated gas yield, wherein the basic parameters comprise: langmuir volume, Langmuir pressure constant, virgin formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, virgin porosity, virgin water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane dissolution factor, formation water volume factor, standard pressure, standard temperature, deviation factor at standard pressure, and water invasion.
And the acquisition module 12 is used for acquiring the formation pressure and the critical desorption pressure.
The first calculation module 13 is configured to calculate the basic parameter, the accumulated water yield and the accumulated gas yield in a first calculation manner when the formation pressure is greater than or equal to the critical desorption pressure, so as to obtain a first average formation pressure of the coal bed methane reservoir at an early drainage stage.
The second calculating module 14 is configured to calculate the basic parameter, the accumulated water yield and the accumulated gas yield in a second calculating manner when the formation pressure is less than the critical desorption pressure, so as to obtain a second average formation pressure of the coal bed gas reservoir in the gas desorption stage.
The apparatus of this embodiment may be used to execute the method for calculating the average formation pressure of the coalbed methane reservoir in the first embodiment, and the specific implementation manner and the technical effect are similar and will not be described again here.
Fig. 8 is a schematic structural diagram of an electronic device according to a fourth embodiment of the present invention, and as shown in fig. 8, the electronic device 200 includes: the processor 21, the memory 22, the transceiver 23, and the memory 22 are configured to store instructions, the transceiver 23 is configured to communicate with other devices, and the processor 21 is configured to execute the instructions stored in the memory, so that the electronic device 200 executes the method steps for calculating average formation pressure of a coalbed methane reservoir in the foregoing embodiment.
An embodiment five of the present invention provides a computer-readable storage medium, where computer-executable instructions are stored in the computer-readable storage medium, and the computer-executable instructions are executed by a processor to implement the method steps for calculating average formation pressure of a coalbed methane reservoir in the foregoing embodiment one, and a specific implementation manner and technical effects are similar, and are not described herein again.
A sixth embodiment of the present invention provides a computer program product, which includes a computer program, and when the computer program is executed by a processor, the method for calculating the average formation pressure of a coal bed methane reservoir in the first embodiment is implemented, and the specific implementation manner and the technical effect are similar, and are not described herein again.
Other embodiments of the present application will be apparent to those skilled in the art from consideration of the specification and practice of the invention disclosed herein. This application is intended to cover any variations, uses, or adaptations of the invention following, in general, the principles of the application and including such departures from the present disclosure as come within known or customary practice within the art to which the invention pertains. It is intended that the specification and examples be considered as exemplary only, with a true scope and spirit of the application being indicated by the following claims.
It will be understood that the present application is not limited to the precise arrangements described above and shown in the drawings and that various modifications and changes may be made without departing from the scope thereof. The scope of the application is limited only by the appended claims.

Claims (10)

1. A method for calculating the average formation pressure of a coal bed gas reservoir is characterized by comprising the following steps:
the method comprises the following steps of counting basic parameters of the coal bed gas reservoir, the accumulative water yield of the coal bed gas well and the accumulative gas yield, wherein the basic parameters comprise: langmuir volume, Langmuir pressure constant, virgin formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, virgin porosity, virgin water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane dissolution factor, formation water volume factor, standard pressure, standard temperature, deviation factor at standard pressure, and water invasion;
acquiring formation pressure and critical desorption pressure;
when the formation pressure is greater than or equal to the critical desorption pressure, calculating the basic parameters, the accumulated water yield and the accumulated gas yield by adopting a first calculation mode to obtain a first average formation pressure of the coal bed gas reservoir in an early drainage stage;
and when the formation pressure is smaller than the critical desorption pressure, calculating the basic parameters, the accumulated water yield and the accumulated gas yield by adopting a second calculation mode to obtain a second average formation pressure of the coal bed gas reservoir in a gas desorption stage.
2. The method of claim 1, wherein the calculating the basic parameters, the accumulated water production and the accumulated gas production by a first calculation method to obtain a first average formation pressure of the coalbed methane reservoir in an early drainage stage comprises:
calculating the first average formation pressure by an iterative process of:
calculating an M value, a free gas original geological reserve, a solution gas original geological reserve and an original pore volume from the reservoir temperature, the standard pressure, a deviation coefficient at the standard pressure, the original water saturation, the original formation pressure, a solubility coefficient for the methane, the single well control area, the coal seam thickness and the original porosity;
fitting according to the gas relative density and the reservoir temperature to obtain a relational expression of pressure and a deviation coefficient;
obtaining a deviation coefficient corresponding to the initial value of the first average lamination pressure according to the initial value of the first average lamination pressure and the relation between the pressure and the deviation coefficient, wherein the initial value of the first average lamination pressure used in the k-th iteration is a calculated value of the first average lamination pressure obtained in the k-1-th iteration;
calculating coefficients a, b and c according to the M value, the original free gas geological reserve, the original solution gas geological reserve, the original pore volume, the current value of the first average formation pressure, the accumulated gas production, the accumulated water production, the original water saturation, the formation compressibility, the formation water volume coefficient and the water invasion;
substituting the coefficients a, b, c into equation (1) to obtain a calculated value of the first average laminate pressure, where equation (1) is:
Figure FDA0003194809910000021
wherein the content of the first and second substances,
Figure FDA0003194809910000022
calculating a first average formation pressure for a kth iteration, wherein k is an iteration number;
when the difference value between the calculated value of the first average lamination pressure obtained by the kth iteration and the initial value of the first average lamination pressure is smaller than a preset first absolute error, ending the iteration process, and taking the calculated value of the first average lamination pressure obtained by the kth iteration as a final value of the first average lamination pressure;
and when the difference value between the calculated value of the first average lamination pressure obtained by the kth iteration and the initial value of the first average lamination pressure is not smaller than the first absolute error, adding 1 to k, and entering the (k + 1) th iteration.
3. The method of claim 2, wherein calculating the M value, the free gas virgin geological reserve, the solution gas virgin geological reserve, and the virgin pore volume from the reservoir temperature, the standard pressure, the coefficient of deviation at the standard pressure, the original water saturation, the original formation pressure, the solubility coefficient of methane, the single well control area, the coal seam thickness, and the original porosity comprises:
calculating the M value, the free gas original geological reserve, the solution gas original geological reserve and the original pore volume using equations (2) - (5):
Figure FDA0003194809910000023
Figure FDA0003194809910000024
Gsi＝VpiSwiCspi (4)
Vpi＝Ahφi (5)
wherein Z isscIs the coefficient of deviation at standard pressure, TscIs a standard temperature, pscIs standard pressure, T is coal reservoir temperature, GfiFor original geological reserves of free gas, VpiTo the original pore volume, SwiIs the original water saturation, piIs the original formation pressure, ZiIs the coefficient of deviation at the original formation pressure, CsIs the solubility coefficient of methane, GsiFor the original geological reserves of solution gas, A is the single well control area, phiiAnd h is the thickness of the coal bed.
4. The method of claim 3, wherein calculating coefficients a, b, c from the M value, the free gas virgin geological reserve, the solution gas virgin geological reserve, the virgin pore volume, the current value of the first average formation pressure, the cumulative gas production, the cumulative water production, the virgin water saturation, the formation compressibility, the formation water volume coefficient, and water invasion comprises:
the coefficients a, b, c are calculated using equations (6) to (8):
Figure FDA0003194809910000031
Figure FDA0003194809910000032
Figure FDA0003194809910000033
wherein k is the number of iterations,
Figure FDA0003194809910000034
the deviation coefficient, C, corresponding to the mean formation pressurepIs the coefficient of pore compressibility, CwIs the formation water compression coefficient, WeWater invasion, WpTo accumulate water production, GpTo accumulate gas production, BwIs the formation water volume factor.
5. The method of claim 4, wherein the calculating the basic parameter, the cumulative water production and the cumulative gas production by the second calculation method to obtain a second average formation pressure of the coalbed methane reservoir in the gas desorption stage comprises:
calculating said M value, said free gas original geological reserve, said solution gas original geological reserve and said original pore volume using equations (2) - (5):
calculating to obtain the original geological reserve G of the adsorbed gas by adopting a formula (9)aiEquation (9) is as follows:
Figure FDA0003194809910000035
wherein G isaiFor adsorbing the gas precursorGeological reserve, VLIs the Langmuir volume, b is the Langmuir pressure constant, pdIs the critical desorption pressure.
Performing an iterative operation on equation (10) to obtain the second average formation pressure, where equation (10) is as follows:
Figure FDA0003194809910000041
wherein, CaThe shrinkage factor of the coal matrix.
6. The method of claim 5, wherein iteratively operating on equation (10) to obtain the second average formation pressure comprises:
the iterative equation for equation (10) is determined as:
Figure FDA0003194809910000042
wherein the F function is:
Figure FDA0003194809910000043
derivation is performed on both sides of equation (12) to obtain equation (13):
Figure FDA0003194809910000044
obtaining a deviation coefficient corresponding to the initial value of the second average lamination pressure according to the initial value of the second average lamination pressure and the relation between the pressure and the deviation coefficient, wherein the initial value of the second average lamination pressure used in the kth iteration is a calculated value of the second average lamination pressure obtained in the kth-1 th iteration;
substituting the deviation coefficient corresponding to the initial value of the second average lamination pressure into the formulas (12) and (13) to calculate the value of the F function and the reciprocal value F' of the F function;
substituting the F function and the derivative value F' of the F function into the formula (11) to carry out Newton iteration to obtain a calculated value of the second average formation pressure obtained by the k-th iteration;
when the difference value between the calculated value of the second average lamination pressure obtained by the kth iteration and the initial value of the second average lamination pressure is smaller than a preset second absolute error, ending the iteration process, and taking the calculated value of the second average lamination pressure obtained by the kth iteration as a final value of the second average lamination pressure;
and when the difference value between the calculated value of the second average lamination pressure obtained by the kth iteration and the initial value of the second average lamination pressure is not less than the second absolute error, adding 1 to k, and entering the kth +1 iteration.
7. An apparatus for calculating average formation pressure of a coalbed methane reservoir, comprising:
the statistical module is used for counting basic parameters of the coal bed gas reservoir, the daily accumulated water yield and the daily accumulated gas yield of the coal bed gas well, and the basic parameters comprise: langmuir volume, Langmuir pressure constant, virgin formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, virgin porosity, virgin water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane dissolution factor, formation water volume factor, standard pressure, standard temperature, deviation factor at standard pressure, and water invasion;
the acquisition module is used for acquiring formation pressure and critical desorption pressure;
the first calculation module is used for calculating the basic parameters, the accumulated water yield and the accumulated gas yield in a first calculation mode to obtain a first average formation pressure of the coal bed gas reservoir in an early drainage stage when the formation pressure is greater than or equal to the critical desorption pressure;
and the second calculation module is used for calculating the basic parameters, the accumulated water yield and the accumulated gas yield in a second calculation mode when the formation pressure is smaller than the critical desorption pressure to obtain a second average formation pressure of the coal bed gas reservoir in a gas desorption stage.
8. An electronic device, comprising: at least one processor and memory;
the memory stores computer-executable instructions;
the at least one processor executing the computer-executable instructions stored by the memory causes the at least one processor to perform the method of any of claims 1-6.
9. A computer-readable storage medium having computer-executable instructions stored thereon, which when executed by a processor, are configured to implement the method of any one of claims 1 to 6.
10. A computer program product comprising a computer program, characterized in that the computer program, when executed by a processor, implements the method of any one of claims 1 to 6.
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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN116127251A (en) * 2023-04-17 2023-05-16 成都英沃信科技有限公司 Stratum pressure monitoring method of carbon dioxide-injected water and gas reservoir
CN116127251B (en) * 2023-04-17 2023-09-29 西南石油大学 Stratum pressure monitoring method of carbon dioxide-injected water and gas reservoir

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