CN113464129B - 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 PDFInfo
- Publication number
- CN113464129B CN113464129B CN202110887725.7A CN202110887725A CN113464129B CN 113464129 B CN113464129 B CN 113464129B CN 202110887725 A CN202110887725 A CN 202110887725A CN 113464129 B CN113464129 B CN 113464129B
- Authority
- CN
- China
- Prior art keywords
- pressure
- gas
- average
- original
- value
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Active
Links
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Geophysics (AREA)
- Treatment Of Sludge (AREA)
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
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, original formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, original porosity, original water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane solubility 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 parameter, 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:
wherein the content of the first and second substances,
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):
G si ＝V pi S wi C s p i (4)
V pi ＝Ahφ i (5)
wherein Z is sc Is the coefficient of deviation, T, at standard pressure sc Is a standard temperature, p sc Is standard pressure, T is coal reservoir temperature, G fi For original geological reserves of free gas, V pi As original pore volume, S wi Is the original water saturation, p i Is the original formation pressure, Z i Is the coefficient of deviation at the original formation pressure, C s Is the solubility coefficient of methane, G si For the original geological reserves of solution gas, A is the single well control area, phi i And 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:
calculating coefficients a, b, c using equations (6) - (8):
wherein k is the number of iterations,
the deviation coefficient, C, corresponding to the mean formation pressure p Is the coefficient of pore compressibility, C w Is the formation water compression coefficient, W e Water invasion, W p To accumulate water production, G p To accumulate gas production, B w Is 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 the original geological reserve G of the adsorbed gas by adopting a formula (9) ai Equation (9) is as follows:
wherein G is ai For adsorbing gas original geological reserves, V L Is Langmuir volume, b is Langmuir pressure constant, p d Is the critical desorption pressure.
Performing an iterative operation on equation (10) to obtain the second average formation pressure, where equation (10) is as follows:
wherein, C a The 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:
wherein the F function is:
derivation is performed on both sides of equation (12) to obtain equation (13):
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 formation pressure obtained by the kth 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 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 production and the accumulated gas production by adopting a first calculation mode when the formation pressure is greater than or equal to the critical desorption pressure to obtain a first average formation pressure of the coal bed gas reservoir in an early drainage stage;
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 computer-executable instructions stored by the memory and the at least one processor executes computer-executable instructions stored by the memory such that the at least one processor performs 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 a device 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. The drawings and written description are not intended to limit the scope of the inventive concepts in any manner, but rather to illustrate the concepts of the application by those skilled in the art with 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 implementations described in the following exemplary examples do not represent all implementations 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 unit of critical Jie Xiya force is MPa, usually denoted by the symbol p d And (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. These several specific embodiments may be combined with each other below, 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 (4) 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.
Basic parameters of coalbed methane reservoirs include: 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 V L | 14 | m 3 /m 3 |
| Langmuir pressure constant b | 0.278 | MPa -1 |
| Pressure p of the original formation i | 9.95 | MPa |
| Critical desorption pressure p d | 7.5 | MPa |
| Single well control area a | 100000 | m 2 |
| Thickness h of coal seam | 21.15 | m |
| Reservoir temperature T | 313.15 | K |
| Relative density of gas gamma g | 0.6 | Dimensionless |
| Original porosity phi i | 0.04 | Decimal fraction |
| Original water saturation S wi | 0.95 | Decimal fraction |
| Coefficient of shrinkage of coal matrix C a | 0.019 | Dimensionless |
| Formation water compressibility factor C w | 0.000425 | Without measuringLine rope |
| Coefficient of pore compression C p | 0.01087 | Dimensionless |
| Coefficient of dissolution C of methane s | 0.044 | MPa -1 |
| Volume coefficient of formation water B w | 1.0 | m 3 /sm 3 |
| Standard pressure p sc | 0.101325 | MPa |
| Standard temperature T sc | 293.15 | K |
| Coefficient of deviation Z at standard pressure sc | 1 | Dimensionless |
| Deviation coefficient Z under virgin formation pressure i | 0.86548377 | Dimensionless |
| Water intrusion W e | 0 | m 3 |
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. 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 formula fi Original geological reserve G of solution gas si And original pore volume V pi ：
G si ＝V pi S wi C s p i (4)
V pi ＝Ahφ i (5)
Wherein Z is sc Is the coefficient of deviation, T, at standard pressure sc Is a standard temperature, p sc Is standard pressure, T is coal reservoir temperature, G fi For original geological reserves of free gas, V pi To the original pore volume, S wi Is the original water saturation, p i To the original formation pressure, Z i Is the coefficient of deviation, C, at the virgin formation pressure s Is the solubility coefficient of methane, G si For the original geological reserves of solution gas, A is the single well control area, phi i And 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 pressure sc Has a value of 1, standard temperature T sc Has a value of 293.15K, standard pressure p sc The 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 (1). Then the original water saturation S is measured wi Has a value of 0.95, the original formation pressure p i Value of 9.95MPa, deviation coefficient Z under the pressure of the original formation i Value of 0.86548377, solubility coefficient of methane C s Has a value of 0.044MPa -1 The value of the single well control area A is 100000m 2 The 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 reservoir pi Is 105750.00m 3 Original geological reserve of free gas G fi Is 561609.96m 3 Original geological reserve G of solution gas si Is 43982.48m 3 。
(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, R 2 =1 represents the plurality of itemsThe fitting effect of the formula is good. The fitting results are as follows:
wherein k is the number of iterations,
is the deviation factor corresponding to the average formation pressure,
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 an AGA8-92DC method, a 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 laminating pressure according to the initial value of the first average laminating pressure and a relation between the pressure and the deviation coefficient, wherein the initial value of the first average laminating pressure used in the kth iteration is a calculated value of the first average laminating pressure obtained in the kth-1 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
Calculating the deviation coefficient corresponding to the initial value according to the relation between the pressure and the deviation coefficient
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:
wherein k is the number of iterations,
is a deviation coefficient corresponding to the average formation pressure, C p Is the coefficient of pore compressibility, C w Is the formation water compression coefficient, W e Amount of water invasion, W p To accumulate the water production, G p To accumulate gas production, B w Is 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, W p Indicating cumulative water production, G p Represents the cumulative gas production, produced in 2014 at 8 months and 13 daysData as an example, G p ＝117469.06m 3 ，W p ＝1367.92m 3 . The values of the parameters shown in Table I and the deviation coefficients corresponding to the initial values of the average formation pressure
Substituting equations (6) - (8) for 0.9523, a is calculated to be 0.1097, b is-0.4398, and c is-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:
wherein, the first and the second end of the pipe are connected with each other,
the calculated value of the first average formation pressure obtained for the kth iteration, k being the number of iterations.
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
Has a value of 8.7935MPa, at which time
And initial value of average formation pressure
The absolute error of (2) is 5.8135MPa, the error is not less than the preset first absolute error of 0.001MPa, and a calculated value is calculated
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
Value of 8.5737MPa and the first average formation pressure obtained in iteration 1
The absolute error 0.2198MPa is not less than the preset first absolute error 0.001MPa, and the calculated value is calculated
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
Value of 8.5806MPa and the first average formation pressure from the 2 nd iteration
The absolute error of 0.0069MPa is not less than the preset first absolute error of 0.001MPa, and the calculated value is calculated
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 to enter the 4 th iteration. First average formation pressure from 4 th iteration
Value of 8.5804MPa and the first average formation pressure obtained in iteration 3
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
The value of 8.5804MPa is taken as the final value of the average formation pressure for the daily coalbed methane reservoir.
Watch two
Figure 4 is a graph of the average formation pressure of a coalbed methane reservoir at an early drainage stage,
to mean formation pressure, p wf For 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 pressure sc Has a value of 1, standard temperature T sc Has a value of 293.15K, standard pressure p sc The value of (A) is 0.101325MPa, the value of the reservoir temperature T is 313.15K, and the M value is obtained by substituting the parameters into the formula (2)9.2389. Then the original water saturation S is measured wi Has a value of 0.95, the original formation pressure p i Has a value of 9.95MPa and a deviation coefficient Z under the original formation pressure i Value of 0.86548377, solubility coefficient of methane C s Has a value of 0.044MPa -1 The value of the single well control area A is 100000m 2 The 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 reservoir pi Is 105750.00m 3 Free gas original geological reserve G fi Is 561609.96m 3 Original geological reserve G of solution gas si Is 43982.48m 3 。
(2) Calculating the original geological reserve G of the adsorbed gas by adopting a formula (9) ai Equation (9) is as follows:
wherein G is ai For adsorbing gas original geological reserves, V L Is the Langmuir volume, b is the Langmuir pressure constant, p d Is 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 100000m 2 The value of the coal seam thickness h is 21.15m, the Langmuir volume V L Has a value of 14m 3 /m 3 The Langmuir pressure constant b was 0.278MPa -1 And critical desorption pressure p d The value of (3) is 7.5MPa, and the original geological reserve G of the adsorbed gas is obtained by substituting the value into a formula (9) ai Is 20006756.76m 3 。
(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:
wherein, C a The 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:
wherein the F function is:
derivation is performed on both sides of equation (12) to obtain equation (13):
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 smaller than a second absolute error, adding 1 to k, and entering the kth +1 iteration.
Illustratively, a coalbed methane reservoir is depleted during a gas desorption phaseFIG. 5 is an example of a graph of cumulative gas production data representing water production p Indicating cumulative water production, G p Represents the cumulative gas production, as exemplified by the production data of 12 months and 23 days in 2015G p ＝1758207.89m 3 ，W p ＝5545.52m 3 The bottom hole flowing pressure is 2.35MPa, and the bottom hole flowing pressure is taken as the initial value of the average formation pressure
Calculating the deviation coefficient corresponding to the initial value according to the relation between the pressure and the deviation coefficient
Is 0.9618.
Illustratively, the cumulative water production W p Cumulative gas production G p Initial value of mean formation pressure
Corresponding deviation coefficient
Substituting the values of the parameters shown in the sum table I into the formulas (12) and (13), and calculating to obtain the values
Will average the initial value of the formation pressure
Calculated to obtain
Value of (A) and
is substituted into equation (11), and the 1 st iteration yields a second average laminate pressure
Has a value of 4.6737MPa at this time
And initial value of average formation pressure
Has an absolute error of 2.3237MPa, which is not less than the second absolute error of 0.001MPa, and calculates the value
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 2 nd iteration is entered.
The results of the iterative calculations are shown in Table three, with the second average formation pressure from iteration 2
Value of 5.8210MPa and the second average formation pressure from the 1 st iteration
1.1472MPa is not less than a preset second absolute error of 0.001MPa, and the calculated value is
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 3 rd iteration is entered. Second average formation pressure from 3 rd iteration
Value of 5.9692MPa and the second average formation pressure from the 2 nd iteration
0.1483MPa is not less than a preset second absolute error of 0.001MPa, and the calculated value is
As an initial value, k plus 1, pressure and coefficient of deviation are repeatedAnd equations (11) - (13), go to iteration 4. Second average formation pressure from iteration 4
Value of 5.9706MPa and the second average formation pressure from the 3 rd iteration
Is not less than 0.0014MPa, and the calculated value is not less than 0.001MPa
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 5 th iteration
Value of 5.9706MPa and the second average formation pressure from the 4 th iteration
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
The value of 5.9706MPa is taken as the final value of the average formation pressure for the daily coalbed methane reservoir.
Watch III
Figure 6 is a graph of the average formation pressure of a coalbed methane reservoir during a gas desorption phase,
to mean formation pressure, p wf The mean formation pressure is always greater than the bottom hole flowing pressure for bottom hole flowing pressureAnd the method is 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.
An obtaining module 12 is used for obtaining formation pressure and 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 device 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 are not 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, 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 layer 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 that have been 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 (7)
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;
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; the 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 at an early drainage stage comprises the following steps:
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:
wherein, the first and the second end of the pipe are connected with each other,
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;
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;
the 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 comprises the following steps:
calculating the M value, the free gas original geological reserve, the solution gas original geological reserve, and the original pore volume:
calculating the original geological reserve G of the adsorbed gas by adopting a formula (9) ai Equation (9) is as follows:
wherein G is ai For adsorbing gas original geological reserves, V L Is the Langmuir volume, b is the Langmuir pressure constant, p d Is the critical desorption pressure;
performing an iterative operation on equation (10) to obtain the second average formation pressure, where equation (10) is as follows:
wherein, C a The shrinkage factor of the coal matrix.
2. The method of claim 1, 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):
G si ＝V pi S wi C s p i (4)
V pi ＝Ahφ i (5)
wherein Z is sc Is the coefficient of deviation, T, at standard pressure sc Is a standard temperature, p sc Is standard pressure, T is coal reservoir temperature, G fi For original geological reserves of free gas, V pi To the original pore volume, S wi Is the original water saturation, p i To the original formation pressure, Z i Is the coefficient of deviation at the original formation pressure, C s Is the solubility coefficient of methane, G si For the original geological reserves of solution gas, A is the single well control area, phi i And h is the thickness of the coal bed.
3. The method of claim 2, 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:
calculating coefficients a, b, c using equations (6) - (8):
wherein k is the number of iterations,
the deviation coefficient, C, corresponding to the mean formation pressure p Is the coefficient of pore compressibility, C w Is the formation water compression coefficient, W e Water invasion, W p To accumulate the water production, G p To accumulate gas production, B w Is the formation water volume factor.
4. The method of claim 1, wherein iteratively operating equation (10) to obtain the second average formation pressure comprises:
the iterative equation for equation (10) is determined as:
wherein the F function is:
derivation is performed on both sides of equation (12) to obtain equation (13):
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 smaller than the second absolute error, adding 1 to k, and entering the kth +1 iteration.
5. 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 of the coal bed gas well and the accumulated gas yield, and the basic parameters comprise: langmuir volume, langmuir pressure constant, original formation pressure, critical desorption pressure, single well control area, coal seam thickness, reservoir temperature, gas relative density, original porosity, original water saturation, coal matrix shrinkage factor, formation water compression factor, pore compression factor, methane solubility 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;
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;
the first calculating module is specifically configured to calculate the first average formation pressure through an iterative process as follows;
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 lamination pressure, where equation (1) is:
wherein pk is a calculated value of the first average formation pressure obtained by the kth iteration, and k is the 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;
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;
the second calculation module is specifically configured to calculate the M value, the free gas original geological reserve, the solution gas original geological reserve, and the original pore volume:
calculating the original geological reserve G of the adsorbed gas by adopting a formula (9) ai Equation (9) is as follows:
wherein, gai is the original geological reserve of the adsorbed gas, VL is the volume of Langmuir, b is the Langmuir pressure constant, and pd is the critical desorption pressure;
performing an iterative operation on equation (10) to obtain the second average formation pressure, where equation (10) is as follows:
wherein Ca is the shrinkage coefficient of the coal matrix.
6. An electronic device, comprising: at least one processor and memory;
the memory stores computer-executable instructions;
execution of the computer-executable instructions stored by the memory by the at least one processor causes the at least one processor to perform the method of any one of claims 1 to 4.
7. 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 4.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202110887725.7A CN113464129B (en) | 2021-08-03 | 2021-08-03 | Method and device for calculating average formation pressure of coal bed gas reservoir |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202110887725.7A CN113464129B (en) | 2021-08-03 | 2021-08-03 | Method and device for calculating average formation pressure of coal bed gas reservoir |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN113464129A CN113464129A (en) | 2021-10-01 |
| CN113464129B true CN113464129B (en) | 2023-02-28 |
Family
ID=77883830
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN202110887725.7A Active CN113464129B (en) | 2021-08-03 | 2021-08-03 | Method and device for calculating average formation pressure of coal bed gas reservoir |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN113464129B (en) |
Families Citing this family (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| 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 |
Family Cites Families (10)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6244338B1 (en) * | 1998-06-23 | 2001-06-12 | The University Of Wyoming Research Corp., | System for improving coalbed gas production |
| EP1896827A4 (en) * | 2005-05-24 | 2017-05-10 | Yates Petroleum Corporation | Methods of evaluating undersaturated coalbed methane reservoirs |
| CN104632187B (en) * | 2013-11-14 | 2017-10-27 | 中国石油化工股份有限公司 | A kind of method for determining production water coal bed gas well dynamic holdup |
| CN106484933B (en) * | 2015-08-31 | 2019-06-18 | 中国石油化工股份有限公司 | It is a kind of for determining the method and system of shale gas well well control dynamic holdup |
| CN110188313A (en) * | 2019-06-03 | 2019-08-30 | 西南石油大学 | A kind of shale gas reservoir reserves method for solving considering many factors |
| CN112528455B (en) * | 2019-09-03 | 2022-10-04 | 中国石油天然气股份有限公司 | Method and system for calculating reservoir pressure and dynamic reserve of adsorption unsaturated coal-bed gas well |
| CN111415031B (en) * | 2020-02-19 | 2023-05-09 | 中石油煤层气有限责任公司 | Method for predicting productivity of coal-bed gas well |
| CN111396020B (en) * | 2020-02-24 | 2022-06-10 | 中石油煤层气有限责任公司 | Evaluation method for interference between coal-bed gas wells |
| CN112613171B (en) * | 2020-12-17 | 2022-09-30 | 中国石油大学(北京) | Coal reservoir permeability determination method and device |
| CN112878987B (en) * | 2021-01-25 | 2024-01-19 | 长江大学 | Method for calculating shale gas well control reserves by using production data |
-
2021
- 2021-08-03 CN CN202110887725.7A patent/CN113464129B/en active Active
Also Published As
| Publication number | Publication date |
|---|---|
| CN113464129A (en) | 2021-10-01 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CN106599449B (en) | Well test interpretation method for karst cave volume calculation | |
| CN104018829B (en) | A kind of method that utilization coal bed gas well creation data measures air water phase percolation curve | |
| CN104573344A (en) | Method for acquiring gas content of shale reservoir through well logging data | |
| CN104612635A (en) | Standard-reaching pre-judgment method for coal seam group gas combined extraction | |
| CN105893679B (en) | Well Test Data Analysis Method is corrected in low yield horizontal well afterflow | |
| EP2643713A1 (en) | System and method for estimating fluid distribution in a subterranean reservoir | |
| CN109281663A (en) | A kind of method of determining coalbed methane reservoir permeability | |
| CN113464129B (en) | Method and device for calculating average formation pressure of coal bed gas reservoir | |
| CN112528455B (en) | Method and system for calculating reservoir pressure and dynamic reserve of adsorption unsaturated coal-bed gas well | |
| CN105822298A (en) | Method for acquiring absolute open flow of shale gas layer based on gas productivity index | |
| CN111911115A (en) | Shale gas well dynamic production allocation method | |
| US20170285221A1 (en) | Generating dynamically calibrated geo-models in green fields | |
| CN108729912B (en) | Yield splitting method suitable for numerical reservoir simulation | |
| CN110955982A (en) | Metamorphic rock reservoir permeability calculation method and device and computer storage medium | |
| CN107130955B (en) | Method for determining bottom hole flowing pressure and method for determining natural energy of reservoir | |
| CN111999227A (en) | Stress sensitivity testing method and device | |
| CN111476448B (en) | Multi-layer combined production vertical well dynamic yield splitting method | |
| CN111241460B (en) | Complex compact reservoir porosity calculation method | |
| CN110442835B (en) | Method for predicting capacity of sand river subgroup sandstone reservoir before vertical well pressure | |
| CN103334740A (en) | Method for confirming oil drainage front edge with consideration of starting pressure gradient | |
| CN107816335B (en) | Method and device for determining lower limit of coal bed gas content development | |
| US20220129609A1 (en) | Hybrid method for reservoir simulation | |
| CN112377184B (en) | Physical property parameter analysis method and device for beaded fracture-cavity type carbonate reservoir | |
| CN110671102B (en) | Method and system for determining critical sand production pressure difference of gas well | |
| CN108629463B (en) | Ground stress change prediction method and device |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination | ||
| GR01 | Patent grant | ||
| GR01 | Patent grant |