Calculation method of natural gas dynamic reserves under the condition of coordinated development of gas reservoir groups

Abstract

The present invention discloses a method for calculating the dynamic reserves of natural gas under the conditions of collaborative development of a gas reservoir group, a processor and a machine-readable storage medium. The calculation method comprises: respectively obtaining reservoir physical property parameters and multiple groups of production dynamic data, calculating the total water production and the total water invasion, respectively calculating the natural gas deviation coefficients corresponding to at least two gas reservoirs under different average formation pressures according to a preset calculation model, obtaining a straight line fitting model established based on an original geological reserve model of the gas reservoir group, randomly selecting a preset reserve ratio within a preset range, and determining a straight line fitting image according to the straight line fitting model, reservoir physical property parameters, production dynamic data, total water production, total water invasion, natural gas deviation coefficient and preset reserve ratio, and determining the original geological reserves of natural gas according to the straight line fitting image, so that the influence of collaborative development is taken into account when calculating the reserves of the gas reservoir group, thereby improving the accuracy of reserve calculation, and the operation is simple and easy.

Description

Technical Field

[0001] The present invention belongs to the technical field of gas reservoir development, and in particular relates to a method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group, a processor and a machine-readable storage medium. Background Art

[0002] The original geological reserves of natural gas in a gas reservoir are generally determined by the volumetric method and the material balance method. The volumetric method is generally used before or in the early stages of gas reservoir development to estimate the original geological reserves of a gas reservoir using the results of geology, geophysical exploration, well logging, etc., and is a static reserve calculation method. The material balance method is mostly used during the development of a gas reservoir to calculate the original geological reserves of a gas reservoir using production dynamic data and average formation pressure data from multiple well shut-ins, and is a dynamic reserve calculation method.

[0003] At the same time, due to complex geological tectonic movements, multiple fault block gas reservoirs connected by the same side bottom water will be formed, that is, gas reservoir groups. During the development process, the pressures between connected gas reservoirs will affect each other. If the reserves of each gas reservoir in the gas reservoir group are calculated separately, the reserves will have a large error. Therefore, it is urgent to propose a method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups, so that such gas reservoirs can be considered uniformly when calculating reserves, so as to accurately calculate the reserves. Summary of the invention

[0004] In view of the above-mentioned defects or shortcomings of the prior art, the present invention provides a method for calculating the dynamic reserves of natural gas under the conditions of collaborative development of a gas reservoir group, a processor and a machine-readable storage medium, aiming to solve the technical problem that the reserves of each gas reservoir in a gas reservoir group will result in large errors in the reserves if the reserves are calculated separately.

[0005] In order to achieve the above-mentioned object, the present invention provides a method for calculating the dynamic reserves of natural gas under the condition of coordinated development of a gas reservoir group in a first aspect, wherein the gas reservoir group includes at least two gas reservoirs, and the method for calculating the dynamic reserves of natural gas under the condition of coordinated development of the gas reservoir group includes:

[0006] Reservoir physical property parameters of at least two gas reservoirs and multiple sets of production performance data under coordinated development conditions are obtained respectively;

[0007] The cumulative water production of at least two gas reservoirs in the same group of production dynamic data is added to obtain the total water production, and the cumulative water invasion of at least two gas reservoirs is added to obtain the total water invasion;

[0008] Calculating the natural gas deviation coefficients corresponding to at least two gas reservoirs at different average formation pressures according to a preset calculation model;

[0009] Obtaining a straight line fitting model established based on an original geological reserve model of the gas reservoir group, wherein the original geological reserve model is established based on a material balance equation of the gas reservoir group;

[0010] Randomly select a preset reserve ratio within a preset range;

[0011] Determine a straight line fitting image according to a straight line fitting model, reservoir physical property parameters, production dynamic data, total water production, total water invasion, natural gas deviation coefficient and preset reserve ratio;

[0012] The original geological reserves of natural gas in the gas reservoir group are determined based on the straight line fitting image.

[0013] In the embodiment of the present invention, the formula of the straight line fitting model is:

[0014] Y = 1-mX;

[0015] in,

[0016]

[0017]

[0018] In the formula, a j is the preset reserve ratio of gas reservoir j to gas reservoir 1, 0 j <1, j = 2, 3, 4…n, dimensionless; T1 is the reservoir temperature of gas reservoir 1, K; p1 is the average formation pressure of gas reservoir 1, MPa; p 1i is the original formation pressure of gas reservoir 1, MPa; Z 1i is the deviation coefficient of the original natural gas in gas reservoir 1, dimensionless; Z1 is the deviation coefficient of the current natural gas in gas reservoir 1, dimensionless; S w1i is the initial water saturation of gas reservoir 1, decimal; C p1 is the pore volume compression coefficient of gas reservoir 1, MPa -1 ; C w1 is the pore water compressibility coefficient of gas reservoir 1, MPa -1 ; G p1 is the cumulative gas production of gas reservoir 1, 10 8 m 3 ; G1 is the original geological reserves of natural gas in gas reservoir 1, 10 8 m 3 ; T j is the reservoir temperature of gas reservoir j, K; p j is the average formation pressure of gas reservoir j, MPa; p ji is the original formation pressure of gas reservoir j, MPa; Z ji is the deviation coefficient of the original natural gas in gas reservoir j, dimensionless; Z j is the current natural gas deviation coefficient of gas reservoir j, dimensionless; S​wji is the initial water saturation of gas reservoir j, decimal; C pj is the pore volume compression coefficient of gas reservoir j, MPa -1 ; C wj is the pore water compressibility coefficient of gas reservoir j, MPa -1 ; G pj is the cumulative gas production of gas reservoir j, 10 8 m 3 ; B w is the formation water volume coefficient, m 3 / sm 3 ; W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 .

[0019] In the embodiment of the present invention, the formula of the original geological reserve model is:

[0020]

[0021] in,

[0022] In the formula, a j is the preset reserve ratio of gas reservoir j to gas reservoir 1, 0 j <1, j = 2, 3, 4…n, dimensionless; T1 is the reservoir temperature of gas reservoir 1, K; p1 is the average formation pressure of gas reservoir 1, MPa; p 1i is the original formation pressure of gas reservoir 1, MPa; Z 1i is the deviation coefficient of the original natural gas in gas reservoir 1, dimensionless; Z1 is the deviation coefficient of the current natural gas in gas reservoir 1, dimensionless; S w1i is the initial water saturation of gas reservoir 1, decimal; C p1 is the pore volume compression coefficient of gas reservoir 1, MPa -1 ; C w1 is the pore water compressibility coefficient of gas reservoir 1, MPa -1 ; G p1 is the cumulative gas production of gas reservoir 1, 10 8 m 3 ; G1 is the original geological reserves of natural gas in gas reservoir 1, 10 8 m 3 ; T j is the reservoir temperature of gas reservoir j, K; p j is the average formation pressure of gas reservoir j, MPa; p ji is the original formation pressure of gas reservoir j, MPa; Z ji ​is the deviation coefficient of the original natural gas in gas reservoir j, dimensionless; Z j is the current natural gas deviation coefficient of gas reservoir j, dimensionless; S wji is the initial water saturation of gas reservoir j, decimal; C pj is the pore volume compressibility coefficient of gas reservoir j, MPa -1 ; C wj is the pore water compressibility coefficient of gas reservoir j, MPa -1 ; G pj is the cumulative gas production of gas reservoir j, 10 8 m 3 ; G j is the original geological reserves of natural gas in reservoir j, 10 8 m 3 ; B w is the formation water volume coefficient, m 3 / sm 3 ; W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 .

[0023] In an embodiment of the present invention, determining the original geological reserves of natural gas of a gas reservoir group according to a straight line fitting image includes:

[0024] Determine an ideal fitting straight line according to the straight line fitting image;

[0025] determining the original geological reserves of natural gas in the first gas reservoir of the at least two gas reservoirs according to the slope of the ideal fitting straight line;

[0026] The original geological reserves of natural gas in the remaining gas reservoirs are determined according to the original geological reserves of natural gas in the first gas reservoir and the preset reserve ratio corresponding to the ideal fitting straight line.

[0027] In an embodiment of the present invention, determining a straight line fitting image according to a straight line fitting model, reservoir physical property parameters, production dynamic data, total water production, total water intrusion, natural gas deviation coefficient, and a preset reserve ratio includes:

[0028] Substitute the preset reserve ratio, reservoir physical property parameters, cumulative gas production and average formation pressure in each set of production dynamic data, and total water production, total water invasion and natural gas deviation coefficient corresponding to each set of production dynamic data into the formula of the linear fitting model to calculate and obtain multiple coordinate values;

[0029] A computer automatic history fitting algorithm is used to perform straight line fitting on multiple coordinate values ​​obtained according to different preset reserve ratios to obtain a straight line fitting image.

[0030] In an embodiment of the present invention, multiple groups of production dynamic data are measured and obtained in different time periods under collaborative development conditions, and each group of production dynamic data includes the cumulative gas production, cumulative water production, cumulative water invasion and average formation pressure of at least two gas reservoirs. The average formation pressure of some missing measurements is calculated by interpolation method based on the cumulative gas production of at least two gas reservoirs.

[0031] In the embodiment of the present invention, the preset calculation model is Dranchuk-Abou-Kassem.

[0032] In the embodiment of the present invention, the reservoir physical property parameters include: formation water volume coefficient, reservoir temperature, original formation pressure, pore water compressibility coefficient, pore volume compressibility coefficient and original water saturation.

[0033] In order to achieve the above-mentioned object, the second aspect of the present invention provides a processor configured to execute the method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group as described above.

[0034] In order to achieve the above objectives, the third aspect of the present invention provides a machine-readable storage medium, on which instructions are stored. When the instructions are executed by a processor, a method for calculating the dynamic reserves of natural gas under the conditions of collaborative development of a gas reservoir group as described above is implemented.

[0035] Through the above technical solution, the method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups provided in the embodiment of the present invention has the following beneficial effects:

[0036] In the above technical scheme, a straight line fitting model is further determined according to the original geological reserve model established based on the material balance equation of the gas reservoir group, and the reservoir physical property parameters of each gas reservoir in the gas reservoir group, multiple groups of production dynamic data of each gas reservoir under the conditions of coordinated development, the total water production and total water invasion corresponding to the multiple groups of production dynamic data, the calculated natural gas deviation coefficient and the randomly selected preset reserve ratio are substituted into the straight line fitting model to perform straight line fitting to obtain a straight line fitting image, and the original geological reserves of natural gas of the gas reservoir group can be determined according to the fitting straight line with the highest fitting accuracy in the straight line fitting image. Therefore, the influence of coordinated development is taken into account when calculating the reserves of the gas reservoir group, thereby improving the accuracy of the reserve calculation, and it is simple and easy to operate.

[0037] Other features and advantages of the embodiments of the present invention will be described in detail in the subsequent detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] The accompanying drawings are used to provide a further understanding of the embodiments of the present invention and constitute a part of the specification. Together with the following specific implementations, they are used to explain the embodiments of the present invention, but do not constitute a limitation on the embodiments of the present invention. In the accompanying drawings:

[0039] Figure 1 is a flow chart of a method for calculating dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group according to an embodiment of the present invention;

[0040] Figure 2 is a flow chart of step 700 in a method for calculating dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group according to an embodiment of the present invention;

[0041] Figure 3 is a flow chart of step 600 in a method for calculating dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group according to an embodiment of the present invention;

[0042] Figure 4 It is a schematic diagram of straight line fitting in Example 1 of the present invention. DETAILED DESCRIPTION

[0043] The specific implementation of the embodiment of the present invention is described in detail below in conjunction with the accompanying drawings. It should be understood that the specific implementation described here is only used to illustrate and explain the embodiment of the present invention, and is not used to limit the embodiment of the present invention.

[0044] It should be noted that if the implementation methods of the present application involve directional indications (such as up, down, left, right, front, back...), such directional indications are only used to explain the relative position relationship, movement status, etc. between the components under a certain specific posture (as shown in the accompanying drawings). If the specific posture changes, the directional indication will also change accordingly.

[0045] In addition, if there are descriptions involving "first", "second", etc. in the implementation methods of this application, the descriptions of "first", "second", etc. are only used for descriptive purposes and cannot be understood as indicating or suggesting their relative importance or implicitly indicating the number of technical features indicated. Therefore, the features defined as "first" and "second" may explicitly or implicitly include at least one of the features. In addition, the technical solutions between the various implementation methods can be combined with each other, but they must be based on the ability of ordinary technicians in the field to implement them. When the combination of technical solutions is contradictory or cannot be implemented, it should be deemed that such combination of technical solutions does not exist and is not within the scope of protection required by this application.

[0046] This paper proposes a material balance dynamic reserve calculation method under the conditions of coordinated development of gas reservoir groups. This method uses the reservoir fluid physical property parameters and dynamic production data of multiple gas reservoirs in the gas reservoir group and adopts the means of linear fitting to simultaneously obtain the original geological reserves of natural gas of multiple gas reservoirs connected by edge and bottom water. The data processing and calculation are relatively simple and easy to promote and apply.

[0047] Figure 1 The flowchart of the method for calculating the dynamic reserves of natural gas under the condition of coordinated development of gas reservoir groups according to one embodiment of the present invention is schematically shown. Figure 1 As shown, the present invention provides a method for calculating the dynamic reserves of natural gas under the condition of coordinated development of a gas reservoir group, wherein the reservoir group includes at least two gas reservoirs, and the method for calculating the dynamic reserves of natural gas under the condition of coordinated development of the gas reservoir group includes the following steps:

[0048] Step 100, respectively obtain reservoir physical property parameters of at least two gas reservoirs and multiple groups of production performance data under collaborative development conditions.

[0049] Specifically, the reservoir physical property parameters may include formation water volume coefficient, reservoir temperature, original formation pressure, pore water compressibility coefficient, pore volume compressibility coefficient and original water saturation, and the above reservoir physical property parameters of at least two gas reservoirs may be counted and recorded respectively. In addition, each set of production dynamic data includes the cumulative gas production, cumulative water production, cumulative water invasion and average formation pressure of each gas reservoir. Under the conditions of coordinated development of gas reservoir groups, multiple sets of production dynamic data may be recorded in chronological order.

[0050] Step 200: Add the accumulated water production of at least two gas reservoirs in the same group of production dynamic data to obtain the total water production and add the accumulated water influx of at least two gas reservoirs to obtain the total water influx.

[0051] Specifically, assuming that there are n gas reservoirs in the gas reservoir group, the cumulative water invasion and cumulative water production of all gas reservoirs in each group are summed up respectively, and the total water invasion and total water production of the coordinated development of the gas reservoir group are calculated. The formula is as follows:

[0052]

[0053]

[0054] Where W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W e1 is the cumulative water intrusion of gas reservoir 1, 10 8 m3 ; W p1 is the cumulative water production of gas reservoir 1, 10 8 m 3 ; W e2 is the cumulative water intrusion of gas reservoir 2, 10 8 m 3 ; W p2 is the cumulative water production of gas reservoir 2, 10 8 m 3 ; W e3 is the cumulative water intrusion of gas reservoir 3, 10 8 m 3 ; W p3 is the cumulative water production of gas reservoir 3, 10 8 m 3 ; W en is the cumulative water intrusion of gas reservoir n, 10 8 m 3 ; W pn is the cumulative water production of gas reservoir n, 10 8 m 3 ; W ej is the cumulative water intrusion of gas reservoir j, 10 8 m 3 ; W pj is the cumulative water production of gas reservoir j, 10 8 m 3 .

[0055] Step 300, calculating the natural gas deviation coefficients corresponding to at least two gas reservoirs at different average formation pressures according to a preset calculation model.

[0056] Specifically, according to the average formation pressure of each gas reservoir, the Dranchuk-Abou-Kassem method can be used to calculate the natural gas deviation coefficient corresponding to each gas reservoir under different average formation pressures. At the same time, the natural gas deviation coefficient includes the original natural gas deviation coefficient and the current natural gas deviation coefficient, both of which can be calculated using the above method.

[0057] Step 400, obtaining a straight line fitting model established based on an original geological reserve model of the gas reservoir group, wherein the original geological reserve model is established based on a material balance equation of the gas reservoir group.

[0058] Specifically, the material balance equation of the gas reservoir group is established, the impact of the coordinated development of n gas reservoirs on production is considered, and the calculation formula of the original geological reserve model of each gas reservoir in the gas reservoir group is derived, so that the calculation formula of the straight line fitting model can be derived based on the original geological reserve calculation formula.

[0059] Step 500: randomly select a preset reserve ratio within a preset range.

[0060] Specifically, the preset reserve ratio is the ratio of the natural gas reserves of the assumed gas reservoir j to the natural gas reserves of gas reservoir 1, j = 2, 3, 4...n. At the same time, if the natural gas reserves of gas reservoir j are less than the natural gas reserves of gas reservoir 1, the preset range of the preset reserve ratio is 0-1.

[0061] Step 600, determining a straight line fitting image according to the straight line fitting model, reservoir physical property parameters, production dynamic data, total water production, total water invasion, natural gas deviation coefficient and preset reserve ratio.

[0062] Furthermore, the calculation formula of the straight-line fitting model includes reservoir physical property parameters, production dynamic data, total water production, total water invasion, natural gas deviation coefficient and preset reserve ratio. A preset reserve ratio can be used to obtain a fitting straight line through straight-line fitting. By selecting multiple preset reserve ratios within a preset range, multiple fitting straight lines can be obtained, thereby forming a straight-line fitting image.

[0063] Step 700: determining the original geological reserves of natural gas in the gas reservoir group based on the straight line fitting image.

[0064] Specifically, the original geological reserves of natural gas in the gas reservoir group can be determined according to the fitting straight line with the highest fitting accuracy in the straight line fitting image.

[0065] In the above technical scheme, a straight line fitting model is further determined according to the original geological reserve model established based on the material balance equation of the gas reservoir group, and the reservoir physical property parameters of each gas reservoir in the gas reservoir group, multiple groups of production dynamic data of each gas reservoir under the conditions of coordinated development, the total water production and total water invasion corresponding to the multiple groups of production dynamic data, the calculated natural gas deviation coefficient and the randomly selected preset reserve ratio are substituted into the straight line fitting model to perform straight line fitting to obtain a straight line fitting image, and the original geological reserves of natural gas of the gas reservoir group can be determined according to the fitting straight line with the highest fitting accuracy in the straight line fitting image. Therefore, the influence of coordinated development is taken into account when calculating the reserves of the gas reservoir group, thereby improving the accuracy of the reserve calculation, and it is simple and easy to operate.

[0066] In the embodiment of the present invention, the formula of the straight line fitting model is:

[0067] Y = 1-mX;

[0068] in,

[0069]

[0070]

[0071] In the formula, a j is the preset reserve ratio of gas reservoir j to gas reservoir 1, 0 j ​<1, j = 2, 3, 4…n, dimensionless; T1 is the reservoir temperature of gas reservoir 1, K; p1 is the average formation pressure of gas reservoir 1, MPa; p 1i is the original formation pressure of gas reservoir 1, MPa; Z 1i is the deviation coefficient of the original natural gas in gas reservoir 1, dimensionless; Z1 is the deviation coefficient of the current natural gas in gas reservoir 1, dimensionless; S w1i is the initial water saturation of gas reservoir 1, decimal; C p1 is the pore volume compression coefficient of gas reservoir 1, MPa -1 ; C w1 is the pore water compressibility coefficient of gas reservoir 1, MPa -1 ; G p1 is the cumulative gas production of gas reservoir 1, 10 8 m 3 ; G1 is the original geological reserves of natural gas in gas reservoir 1, 10 8 m 3 ; T j is the reservoir temperature of gas reservoir j, K; p j is the average formation pressure of gas reservoir j, MPa; p ji is the original formation pressure of gas reservoir j, MPa; Z ji is the deviation coefficient of the original natural gas in gas reservoir j, dimensionless; Z j is the current natural gas deviation coefficient of gas reservoir j, dimensionless; S wji is the initial water saturation of gas reservoir j, decimal; C pj is the pore volume compressibility coefficient of gas reservoir j, MPa -1 ; C wj is the pore water compressibility coefficient of gas reservoir j, MPa -1 ; G pj is the cumulative gas production of gas reservoir j, 10 8 m 3 ; B w is the formation water volume coefficient, m 3 / sm 3 ; W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 It should be noted that it is well known to those skilled in the art that: sc is the standard pressure, 0.101325MPa; T sc is the standard temperature, 293.15K; Z sc It is the natural gas deviation coefficient under standard conditions, dimensionless and always equal to 1.

[0072] In the embodiment of the present invention, the formula of the original geological reserve model is:

[0073]

[0074] in,

[0075] In the formula, a j is the preset reserve ratio of gas reservoir j to gas reservoir 1, 0 j <1, j = 2, 3, 4…n, dimensionless; T1 is the reservoir temperature of gas reservoir 1, K; p1 is the average formation pressure of gas reservoir 1, MPa; p 1i is the original formation pressure of gas reservoir 1, MPa; Z 1i is the deviation coefficient of the original natural gas in gas reservoir 1, dimensionless; Z1 is the deviation coefficient of the current natural gas in gas reservoir 1, dimensionless; S w1i is the initial water saturation of gas reservoir 1, decimal; C p1 is the pore volume compression coefficient of gas reservoir 1, MPa -1 ; C w1 is the pore water compressibility coefficient of gas reservoir 1, MPa -1 ; G p1 is the cumulative gas production of gas reservoir 1, 10 8 m 3 ; G1 is the original geological reserves of natural gas in gas reservoir 1, 10 8 m 3 ; T j is the reservoir temperature of gas reservoir j, K; p j is the average formation pressure of gas reservoir j, MPa; p ji is the original formation pressure of gas reservoir j, MPa; Z ji is the deviation coefficient of the original natural gas in gas reservoir j, dimensionless; Z j is the current natural gas deviation coefficient of gas reservoir j, dimensionless; S wji is the initial water saturation of gas reservoir j, decimal; C pj is the pore volume compressibility coefficient of gas reservoir j, MPa -1 ; C wj is the pore water compressibility coefficient of gas reservoir j, MPa -1 ; G pj is the cumulative gas production of gas reservoir j, 10 8 m 3 ; G j is the original geological reserves of natural gas in reservoir j, 10 8 m 3 ; B w is the formation water volume coefficient, m 3 / sm 3 ; W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m​3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 It should be noted that it is well known to those skilled in the art that: sc is the standard pressure, 0.101325MPa; T sc is the standard temperature, 293.15K; Z sc It is the natural gas deviation coefficient under standard conditions, dimensionless and always equal to 1.

[0076] Figure 2 The flowchart of step 700 in the method for calculating the dynamic reserves of natural gas under the condition of coordinated development of gas reservoir groups according to one embodiment of the present invention is schematically shown. Figure 2 As shown, in the embodiment of the present invention, step 700, determining the original geological reserves of natural gas of the gas reservoir group according to the straight line fitting image includes:

[0077] Step 710: determine an ideal fitting straight line according to the straight line fitting image.

[0078] Specifically, the fitting straight line with the highest fitting accuracy in the straight line fitting image is determined as the ideal fitting straight line.

[0079] Step 720: Determine the original geological reserves of natural gas of the first gas reservoir among the at least two gas reservoirs according to the slope of the ideal fitting straight line.

[0080] Furthermore, the linear fitting formula can be determined according to the ideal fitting straight line, thereby obtaining the absolute value m of the slope of the straight line. Then, the calculation formula for the original geological reserves of natural gas in the first gas reservoir is:

[0081]

[0082] It should be noted that the first gas reservoir is the gas reservoir 1 mentioned above. When the reservoir physical properties and multiple sets of production dynamic data of each gas reservoir are obtained, the cumulative gas production of each gas reservoir corresponding to the last pressure measurement time of the gas reservoir group can be compared, and each gas reservoir can be numbered in order from large to small.

[0083] Step 730: Determine the original geological reserves of natural gas in the remaining gas reservoirs according to the original geological reserves of natural gas in the first gas reservoir and the preset reserve ratio corresponding to the ideal fitting straight line.

[0084] Specifically, if there are more than three gas reservoirs in the gas reservoir group, the preset reserve ratios of the ideal fitting straight line are determined as a2, a3, ..., a j , …, a n The original geological reserves of natural gas in the first gas reservoir are G1, and the calculation formula for the original geological reserves of natural gas in the remaining gas reservoirs is:

[0085] G j =a j G1

[0086] j=2,3,...,n

[0087] Figure 3 The flowchart of step 600 in the method for calculating the dynamic reserves of natural gas under the condition of coordinated development of gas reservoir groups according to one embodiment of the present invention is schematically shown. Figure 3 As shown, in the embodiment of the present invention, step 600, determining the straight line fitting image according to the straight line fitting model, reservoir physical property parameters, production dynamic data, total water production, total water invasion, natural gas deviation coefficient and preset reserve ratio includes:

[0088] Step 610, the preset reserve ratio, reservoir physical parameters, cumulative gas production and average formation pressure in each set of production dynamic data, and total water production, total water invasion and natural gas deviation coefficient corresponding to each set of production dynamic data are respectively substituted into the formula of the linear fitting model to calculate multiple coordinate values.

[0089] Step 620 , using a computer automatic history fitting algorithm to perform straight line fitting on a plurality of coordinate values ​​obtained according to different preset reserve ratios, to obtain a straight line fitting image.

[0090] Specifically, for a set of preset reserve ratios, the cumulative gas production and average formation pressure in different groups of production dynamic data and the corresponding total water production, total water invasion and natural gas deviation coefficient can be substituted respectively to calculate multiple coordinate values ​​(X, Y). The number of groups of production dynamic data is the same as the number of coordinate values ​​(X, Y) corresponding to each preset reserve ratio, and straight line fitting can be performed based on the multiple coordinate values ​​(X, Y). By selecting multiple sets of preset reserve ratios, multiple fitting straight lines can be obtained, and multiple fitting straight lines can form a straight line fitting image.

[0091] At the same time, if the number of gas reservoirs in the gas reservoir group is more than 3, the number of preset reserve ratios in a set of preset reserve ratios is more than 2. The manual fitting process is complicated and may result in multiple solutions. In this case, it is recommended to use computer automatic history fitting. Assume that a2, a3, ..., a j , …, a n Take any value between (0 and 1), fix the intercept of the straight line to 1, and perform Y-X straight line fitting. Find a set of a2, a3, ..., a with the highest fitting accuracy. j , …, a n If there are two gas reservoirs in the gas reservoir group, that is, n = 2, assume an a2 value, calculate and obtain the Y-X image, perform linear fitting and observe the intercept. If the linear intercept is greater than 1, appropriately reduce the a2 value; if the linear intercept is less than 1, appropriately increase the a2 value. When the error between the linear intercept and 1 is less than 10-8 When , it means that the value of a2 is reasonable.

[0092] In an embodiment of the present invention, multiple groups of production dynamic data are measured and obtained in different time periods under collaborative development conditions, and each group of production dynamic data includes the cumulative gas production, cumulative water production, cumulative water invasion and average formation pressure of at least two gas reservoirs. The average formation pressure of some missing measurements is calculated by interpolation method based on the cumulative gas production of at least two gas reservoirs.

[0093] Specifically, at least two gas reservoirs in a gas reservoir group are developed collaboratively. If the pressure measurement data of different gas reservoirs are not obtained on the same date, it is necessary to supplement the average formation pressure data corresponding to the same time. The average formation pressure data can be interpolated according to the cumulative gas production of each gas reservoir to obtain all the required data.

[0094] In the embodiment of the present invention, the preset calculation model may be Dranchuk-Abou-Kassem.

[0095] Further, the Dranchuk-Abou-Kassem method is applied, and according to the natural gas relative density and reservoir temperature of each gas reservoir in the gas reservoir group, the natural gas deviation coefficient of each gas reservoir in the gas reservoir group under different average formation pressures is calculated. In addition, the natural gas deviation coefficient may include the original natural gas deviation coefficient and the current natural gas deviation coefficient.

[0096] In the embodiment of the present invention, the reservoir physical property parameters include: formation water volume coefficient, reservoir temperature, original formation pressure, pore water compressibility coefficient, pore volume compressibility coefficient and original water saturation.

[0097] Example Example 1: A gas reservoir group contains three gas reservoirs connected by the same bottom water, namely, gas reservoir 1, gas reservoir 2 and gas reservoir 3. These three gas reservoirs are developed in a coordinated manner, and the pressure measurement times may not correspond to each other.

[0098] 1. Organize and compile the reservoir physical parameters and production dynamic data of each gas reservoir

[0099] The basic parameters of the reservoirs where gas reservoirs 1, 2 and 3 are located are statistically recorded in Table 1, and the production dynamic data of gas reservoirs 1, 2 and 3 are obtained and recorded in Table 2.

[0100] Table 1 Statistics of reservoir physical properties

[0101]

[0102] Table 2 Production dynamic data of gas reservoir collaborative development

[0103]

[0104]

[0105] 2. Calculate the average formation pressure of the vacancy using the interpolation method

[0106] As shown in Table 2, some average formation pressure data are missing, so the average formation pressure of gas reservoir 1, gas reservoir 2 and gas reservoir 3 is interpolated according to the cumulative gas production, as shown in Table 3:

[0107] Table 3 Interpolation table of average formation pressure data of collaborative development gas reservoirs

[0108]

[0109]

[0110] 3. Calculate the total water intrusion and total water production of the coordinated development of gas reservoirs

[0111] The total water production of the gas reservoir group is obtained by adding the cumulative water production of gas reservoir 1, gas reservoir 2 and gas reservoir 3 at the same time, and the total water invasion of the gas reservoir group is obtained by adding the cumulative water invasion of gas reservoir 1, gas reservoir 2 and gas reservoir 3 at the same time, as shown in Table 4:

[0112] Table 4 Total cumulative water production and water intrusion of gas reservoirs

[0113]

[0114]

[0115] 4. Calculate the natural gas deviation coefficient corresponding to the average formation pressure of each gas reservoir in the gas reservoir group

[0116] According to the average formation pressure of gas reservoir 1, gas reservoir 2 and gas reservoir 3, the Dranchuk-Abou-Kassem method can be used to calculate the natural gas deviation coefficient corresponding to different average formation pressures of gas reservoir 1, gas reservoir 2 and gas reservoir 3. As shown in Table 5:

[0117] Table 5 Natural gas deviation coefficients of gas reservoirs 1, 2 and 3

[0118]

[0119]

[0120] 5. Assume and determine the reserve ratio

[0121] The gas reservoir group in this embodiment has 3 gas reservoirs, n=3, and X and Y are calculated according to the formula of the straight line fitting model. By using the computer to automatically fit the values ​​of a2 and a3, it is found that when a2 is 0.88851942 and a3 is 0.2205423, the error is less than 10 -8 , X and Y data are shown in Table 6.

[0122] Table 6 X and Y data table when a2=0.88851942 and a3=0.2205423

[0123] X Value Y Value 0.0000 1.0000 0.4920 0.9979 0.7125 0.9969 2.5409 0.9927 7.2560 0.9820 9.2046 0.9777 13.1780 0.9658 14.2047 0.9624 15.0085 0.9602 22.1346 0.9361 35.7873 0.8997 37.7266 0.8945 39.0057 0.8915 39.3037 0.8910 57.2134 0.8506 67.5425 0.8267 68.1476 0.8253 90.7549 0.7550 99.2432 0.7284 102.0825 0.7190

[0124] According to Table 6, the X and Y values ​​can be plotted and fitted with a straight line. The fitting results are as follows: Figure 4 shown.

[0125] 6. Determine the original geological reserves of the gas reservoir group based on image parameters

[0126] The linear fitting formula can be determined by the above steps, thereby obtaining the absolute value of the slope of the straight line m = 0.0026981362 ((10 8 m 3 ) -1 ), then the original geological reserves of natural gas in gas reservoir 1 are: The final determined a2 value can be used to calculate the original geological reserves of natural gas in gas reservoir 2: G2 = a2G1 = 329.3086 (10 8 m 3 ), the original geological reserves of natural gas in gas reservoir 3 can be calculated based on the final determined value of a3: G3 = a3G1 = 81.7388 (10 8 m 3 ).

[0127] The present invention is based on the material balance principle, takes into account the effects of pore shrinkage, bound water expansion, water invasion and water production in gas reservoirs connected by edge and bottom water during production, and proposes a new method for calculating the original geological reserves of natural gas under the conditions of coordinated development of gas reservoirs. The method only requires the production dynamic data of each gas reservoir in the gas reservoir group, combines the basic formation parameters of each gas reservoir, calculates the corresponding Y and X values ​​for straight line fitting, and adjusts the parameters to determine the fitting straight line. According to the absolute value of the slope of the fitting straight line, the original geological reserves of natural gas of multiple gas reservoirs can be calculated simultaneously, and the method is simple and easy to operate.

[0128] In addition, another embodiment of the present invention provides a processor configured to execute the method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group as described above.

[0129] In addition, another embodiment of the present invention provides a machine-readable storage medium having instructions stored thereon, which, when executed by a processor, implements the method for calculating the dynamic reserves of natural gas under the conditions of collaborative development of a gas reservoir group as described above.

[0130] Those skilled in the art will appreciate that the embodiments of the present application may be provided as methods, systems, or computer program products. Therefore, the present application may adopt the form of a complete hardware embodiment, a complete software embodiment, or an embodiment in combination with software and hardware. Moreover, the present application may adopt the form of a computer program product implemented in one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) that include computer-usable program code.

[0131] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or box in the flowchart and / or block diagram, as well as the combination of the processes and / or boxes in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0132] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0133] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0134] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0135] The memory may include non-permanent memory in a computer-readable medium, random access memory (RAM) and / or non-volatile memory in the form of read-only memory (ROM) or flash RAM. The memory is an example of a computer-readable medium.

[0136] Computer readable media include permanent and non-permanent, removable and non-removable media that can be implemented by any method or technology to store information. Information can be computer readable instructions, data structures, program modules or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technology, compact disk read-only memory (CD-ROM), digital versatile disk (DVD) or other optical storage, magnetic cassettes, magnetic tape magnetic disk storage or other magnetic storage devices or any other non-transmission media that can be used to store information that can be accessed by a computing device. As defined herein, computer readable media does not include temporary computer readable media (transitory media), such as modulated data signals and carrier waves.

[0137] It should also be noted that the terms "include", "comprises" or any other variations thereof are intended to cover non-exclusive inclusion, so that a process, method, commodity or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, commodity or device. In the absence of more restrictions, the elements defined by the sentence "comprises a ..." do not exclude the existence of other identical elements in the process, method, commodity or device including the elements.

[0138] The above are only embodiments of the present application and are not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application should be included within the scope of the claims of the present application.

Claims

1. A method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups, characterized in that: The gas reservoir group includes at least two gas reservoirs, and the calculation method includes: Respectively obtaining reservoir physical property parameters of at least two of the gas reservoirs and multiple groups of production performance data under collaborative development conditions; The cumulative water production of at least two gas reservoirs in the same group of production dynamic data is added together to obtain a total water production, and the cumulative water influx of at least two gas reservoirs is added together to obtain a total water influx; Calculating the natural gas deviation coefficients corresponding to at least two gas reservoirs at different average formation pressures according to a preset calculation model; Acquire a straight line fitting model established based on an original geological reserve model of the gas reservoir group, wherein the original geological reserve model is established based on a material balance equation of the gas reservoir group; Randomly select a preset reserve ratio within a preset range; Determine a straight line fitting image according to the straight line fitting model, the reservoir physical property parameters, the production dynamic data, the total water production, the total water invasion, the natural gas deviation coefficient and the preset reserve ratio; Determine the original geological reserves of natural gas of the gas reservoir group according to the straight line fitting image; Wherein, the formula of the straight line fitting model is: Y = 1-mX; in, In the formula, a j is the preset reserve ratio of gas reservoir j to gas reservoir 1, 0 j <1, j = 2, 3, 4…n, dimensionless; T1 is the reservoir temperature of gas reservoir 1, K; p1 is the average formation pressure of gas reservoir 1, MPa; p 1i is the original formation pressure of gas reservoir 1, MPa; Z 1i is the deviation coefficient of the original natural gas in gas reservoir 1, dimensionless; Z1 is the deviation coefficient of the current natural gas in gas reservoir 1, dimensionless; S w1i is the initial water saturation of gas reservoir 1, decimal; C p1 is the pore volume compression coefficient of gas reservoir 1, MPa -1 ; C w1 is the pore water compressibility coefficient of gas reservoir 1, MPa -1 ; G p1 is the cumulative gas production of gas reservoir 1, 10 8 m 3 ; G1 is the original geological reserves of natural gas in gas reservoir 1, 10 8 m 3 ; T j is the reservoir temperature of gas reservoir j, K; p j is the average formation pressure of gas reservoir j, MPa; p ji is the original formation pressure of gas reservoir j, MPa; Z ji is the deviation coefficient of the original natural gas in gas reservoir j, dimensionless; Z j is the current natural gas deviation coefficient of gas reservoir j, dimensionless; S wji is the initial water saturation of gas reservoir j, decimal; C pj is the pore volume compressibility coefficient of gas reservoir j, MPa -1 ; C wj is the pore water compressibility coefficient of gas reservoir j, MPa -1 ; G pj is the cumulative gas production of gas reservoir j, 10 8 m 3 ; B w is the formation water volume coefficient, m 3 / sm 3 ; W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 .​ 2. The method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups according to claim 1, characterized in that: The formula of the original geological reserve model is: in, In the formula, a j is the preset reserve ratio of gas reservoir j to gas reservoir 1, 0 j <1, j = 2, 3, 4…n, dimensionless; T1 is the reservoir temperature of gas reservoir 1, K; p1 is the average formation pressure of gas reservoir 1, MPa; p 1i is the original formation pressure of gas reservoir 1, MPa; Z 1i is the deviation coefficient of the original natural gas in gas reservoir 1, dimensionless; Z1 is the deviation coefficient of the current natural gas in gas reservoir 1, dimensionless; S w1i is the initial water saturation of gas reservoir 1, decimal; C p1 is the pore volume compression coefficient of gas reservoir 1, MPa -1 ; C w1 is the pore water compressibility coefficient of gas reservoir 1, MPa -1 ; G p1 is the cumulative gas production of gas reservoir 1, 10 8 m 3 ; G1 is the original geological reserves of natural gas in gas reservoir 1, 10 8 m 3 ; T j is the reservoir temperature of gas reservoir j, K; p j is the average formation pressure of gas reservoir j, MPa; p ji is the original formation pressure of gas reservoir j, MPa; Z ji is the deviation coefficient of the original natural gas in gas reservoir j, dimensionless; Z j is the current natural gas deviation coefficient of gas reservoir j, dimensionless; S wji is the initial water saturation of gas reservoir j, decimal; C pj is the pore volume compressibility coefficient of gas reservoir j, MPa -1 ; C wj is the pore water compressibility coefficient of gas reservoir j, MPa -1 ; G pj is the cumulative gas production of gas reservoir j, 10 8 m 3 ; G j is the original geological reserves of natural gas in reservoir j, 10 8 m 3 ; B w is the formation water volume coefficient, m 3 / sm 3 ; W e is the total water intrusion of all gas reservoirs in the gas reservoir group, 10 8 m 3 ; W p is the total water production of all gas reservoirs in the gas reservoir group, 10 8 m 3 .​ 3. The method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups according to claim 2, characterized in that: Determining the original geological reserves of natural gas of the gas reservoir group according to the straight line fitting image includes: Determine an ideal fitting straight line according to the straight line fitting image; Determining the original geological reserves of natural gas of a first gas reservoir among the at least two gas reservoirs according to the slope of the ideal fitting straight line; The original geological reserves of natural gas in the remaining gas reservoirs are determined according to the original geological reserves of natural gas in the first gas reservoir and the preset reserve ratio corresponding to the ideal fitting straight line.

4. The method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups according to claim 1, characterized in that: Determining a straight-line fitting image according to the straight-line fitting model, the reservoir physical property parameters, the production dynamic data, the total water production, the total water invasion, the natural gas deviation coefficient, and the preset reserve ratio includes: Substituting the preset reserve ratio, the reservoir physical property parameters, the cumulative gas production and the average formation pressure in each group of the production dynamic data, and the total water production, the total water invasion and the natural gas deviation coefficient corresponding to each group of the production dynamic data into the formula of the straight line fitting model, respectively, to calculate a plurality of coordinate values; A computer automatic history fitting algorithm is used to perform straight-line fitting on a plurality of coordinate values ​​obtained according to different preset reserve ratios to obtain the straight-line fitting image.

5. The method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups according to any one of claims 1 to 4, characterized in that: The multiple groups of production dynamic data are measured and obtained in different time periods under collaborative development conditions. Each group of production dynamic data includes the cumulative gas production, cumulative water production, cumulative water invasion and average formation pressure of at least two of the gas reservoirs. The average formation pressure of some missing measurements is calculated by interpolation method based on the cumulative gas production of at least two of the gas reservoirs.

6. The method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups according to any one of claims 1 to 4, characterized in that: The preset calculation model is Dranchuk-Abou-Kassem.

7. The method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of gas reservoir groups according to any one of claims 1 to 4, characterized in that: The reservoir physical property parameters include: formation water volume coefficient, reservoir temperature, original formation pressure, pore water compressibility coefficient, pore volume compressibility coefficient and original water saturation.

8. A processor, characterized in that: The method is configured to execute the method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group according to any one of claims 1 to 7.

9. A machine-readable storage medium having instructions stored thereon, characterized in that: When the instructions are executed by the processor, the method for calculating the dynamic reserves of natural gas under the conditions of coordinated development of a gas reservoir group according to any one of claims 1 to 7 is implemented.

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