Evaluation Method for Original Geological Reserves of Natural Gas in Fractured Gas Reservoirs

Abstract

The present invention discloses a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir includes obtaining the water volume change rate and the rock pore volume change rate; calculating the equivalent apparent pressure based on the basic parameters of the gas reservoir, production dynamic data, water volume change rate, and rock pore volume change rate; determining the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir according to the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir, and determining the original geological reserves of natural gas in the gas reservoir according to the functional relationship. Since this method takes into account the changes in water volume and rock pore volume during the exploitation process, and considers the change in the rock pore volume compressibility when calculating the change in rock pore volume, and converts the pressure of the entire gas reservoir into equivalent apparent pressure, the purpose of obtaining a more accurate calculation result when calculating the original geological reserves of a special fractured gas reservoir is achieved.

Description

Technical Field

[0001] The present invention belongs to the technical field of natural gas exploitation, and particularly relates to a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir. Background Art

[0002] The original geological reserves of natural gas in a gas reservoir are the primary key parameters for developing the gas reservoir, which can directly affect the division of gas reservoir reserves, the calculation of development benefits, and the determination of the development sequence. Before or at the initial stage of gas reservoir development, the original geological reserves of natural gas in the gas reservoir are generally estimated by the volumetric method. During the gas reservoir development process, the original geological reserves of natural gas in the gas reservoir are generally determined by the material balance method, that is, the gas reservoir is regarded as a container with a constant volume, and then the basic parameters of the reservoir and the production dynamic data are used to calculate the original geological reserves of natural gas in the gas reservoir. Currently, there are many types of gas reservoirs. Especially for special gas reservoirs with abnormal high pressure and fractures, the numerical value of the rock pore volume compressibility coefficient is relatively large and changes with the pressure, resulting in the change of the volume of rock pores and the volume of water inside the gas reservoir with the progress of exploitation. At this time, if the conventional gas reservoir material balance method is used to calculate the original geological reserves of natural gas in the gas reservoir, the calculation result will be quite different from the actual situation. Summary of the Invention

[0003] In view of the above defects or deficiencies, the present invention provides a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir, so as to more accurately explore and calculate the original geological reserves of natural gas in special fractured gas reservoirs.

[0004] To achieve the above object, the present invention provides a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir includes:

[0005] Obtaining the water volume change rate and the rock pore volume change rate;

[0006] Calculating the equivalent apparent pressure according to the basic parameters of the gas reservoir, the production dynamic data, the water volume change rate, and the rock pore volume change rate;

[0007] Determining the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir according to the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir, and determining the original geological reserves of natural gas in the gas reservoir according to the functional relationship.

[0008] In an embodiment of the present invention, before obtaining the water volume change rate and the rock pore volume change rate, it further includes statistically analyzing the basic parameters and production dynamic data of the gas reservoir. The basic parameters of the gas reservoir include the original formation pressure of the gas reservoir, the volume compressibility coefficient of water, the overburden pressure, the original reservoir water saturation, the pore volume compressibility coefficient under zero effective stress, and the attenuation coefficient of pore pressure varying with effective stress; the production dynamic data includes the current average formation pressure of the gas reservoir, the current gas compressibility factor, and the cumulative gas production of the gas reservoir.

[0009] In an embodiment of the present invention, obtaining the water volume change rate includes:

[0010] Statistically analyzing the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, and the volume compressibility coefficient of water;

[0011] Calculating the water volume change rate based on the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, and the volume compressibility coefficient of water.

[0012] In an embodiment of the present invention, the calculation formula for the water volume change rate is:

[0013]

[0014] Where ε w is the formation water volume change rate, dimensionless; ΔV w is the formation water volume change amount, with the unit of 10 8 m 3 ; V wi is the original formation water volume, with the unit of 10 8 m 3 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; C w is the volume compressibility coefficient of water, with the unit of MPa -1 .

[0015] In an embodiment of the present invention, obtaining the rock pore volume change rate includes:

[0016] Statistically analyzing the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility coefficient under zero effective stress, and the attenuation coefficient of pore pressure varying with effective stress;

[0017] Calculating the rock pore volume change rate based on the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility coefficient under zero effective stress, and the attenuation coefficient of pore pressure varying with effective stress.

[0018] In an embodiment of the present invention, when considering the change in the pore volume compressibility coefficient, the calculation formula for the rock pore volume change rate is:

[0019]

[0020] where ε pv is the change rate of rock pore volume, dimensionless; ΔV p is the change amount of rock pore volume, with the unit of 10 8 m 3 ; V pi is the original rock pore volume, with the unit of 10 8 m 3 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; p ob is the overburden pressure, with the unit of MPa; C p0 is the pore volume compressibility under zero effective stress, with the unit of MPa -1 ; γ is the attenuation coefficient of pore pressure with respect to the change of effective stress, dimensionless.

[0021] In the embodiment of the present invention, when the change of pore volume compressibility is not considered, the calculation formula of the change rate of rock pore volume is:

[0022]

[0023] where

[0024]

[0025] where ε pc is the change rate of rock pore volume, dimensionless; C pi is the original pore volume compressibility of the rock, with the unit of MPa -1 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; p ob is the overburden pressure, with the unit of MPa; C p0 is the pore volume compressibility under zero effective stress, with the unit of MPa -1 ; γ is the attenuation coefficient of pore pressure with respect to the change of effective stress, dimensionless.

[0026] In the embodiment of the present invention, the calculation formula of the equivalent apparent pressure is:

[0027]

[0028] where Y is the equivalent apparent pressure, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; Z is the current gas compressibility factor, dimensionless; S wi is the original reservoir water saturation, fraction; ε wis the formation water volume change rate, dimensionless; ε p is the rock pore volume change rate, dimensionless.

[0029] In the embodiments of the present invention, the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir, determined according to the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir, includes:

[0030] Calculate the values of multiple groups of equivalent apparent pressures and count the values of the corresponding cumulative gas production of the gas reservoir;

[0031] According to the values of multiple groups of equivalent apparent pressures and the values of the corresponding cumulative gas production of the gas reservoir, use curve fitting to determine the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir.

[0032] In the embodiments of the present invention, the curve fitting is linear fitting, and the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir is a linear function.

[0033] In the embodiments of the present invention, determining the original in-situ gas reserves of the gas reservoir according to the linear function includes:

[0034] Calculate the intercept and slope of the linear function;

[0035] Calculate the original in-situ gas reserves of the gas reservoir according to the intercept and slope of the linear function; the calculation formula for the original in-situ gas reserves of the gas reservoir is:

[0036]

[0037] where G is the original in-situ gas reserves of the gas reservoir, a is the absolute value of the slope, and b is the intercept.

[0038] Through the above technical solutions, the method for evaluating the original in-situ gas reserves of a fractured gas reservoir provided by the embodiments of the present invention has the following beneficial effects:

[0039] When using the above calculation method to calculate the original in-situ gas reserves of a special fractured gas reservoir, by obtaining the water volume change rate and the rock pore volume change rate, and combining the basic parameters and production dynamic data of the gas reservoir to calculate the equivalent apparent pressure corresponding to the current average formation pressure of the gas reservoir, and by determining the relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir, the original in-situ gas reserves of this special gas reservoir can be calculated. Since the method of the present invention takes into account the changes in water volume and rock pore volume during the exploitation process, and converts the pressure of the entire gas reservoir into equivalent apparent pressure, by determining the relationship between the equivalent apparent pressure and the cumulative gas production, the purpose of obtaining a more accurate calculation result when calculating the original in-situ gas reserves of a special fractured gas reservoir is achieved.

[0040] Other features and advantages of the present invention will be described in detail in the subsequent specific implementation part. Brief Description of the Drawings

[0041] The drawings are used to provide an understanding of the present invention and form a part of the specification. Together with the following detailed implementation manners, they are used to explain the present invention, but do not constitute a limitation to the present invention. In the drawings:

[0042] Figure 1 Schematically shows a flowchart of the steps of a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention;

[0043] Figure 2 Schematically shows a flowchart of step S10 in the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention;

[0044] Figure 3 Schematically shows another flowchart of step S10 in the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention;

[0045] Figure 4 Schematically shows a flowchart of step S30 in the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention;

[0046] Figure 5 is the cumulative gas production G of the gas reservoir after curve fitting according to an embodiment of the present invention p Graph of the relationship with the equivalent apparent pressure Y. Detailed Implementation Manners

[0047] The following describes in detail specific embodiments of the present invention with reference to the drawings. It should be understood that the specific embodiments described herein are only used to illustrate and explain the present invention, and are not used to limit the present invention.

[0048] The following describes a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir of the present invention with reference to the drawings.

[0049] Figure 1 Schematically shows a flowchart of the steps of a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention. As Figure 1 shown, the present invention provides a method for evaluating the original geological reserves of natural gas in a fractured gas reservoir, wherein the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir includes the following steps:

[0050] Step S10: Obtain the water volume change rate and the rock pore volume change rate.

[0051] Among them, the change rate of rock pore volume is defined as the ratio of the change in rock pore volume when the pressure changes from the original formation pressure to the current pressure to the original rock pore volume; the change rate of formation water volume is defined as the ratio of the change in formation water volume when the pressure changes from the original formation pressure to the current pressure to the original formation water volume.

[0052] Step S20: Calculate the equivalent apparent pressure based on the basic parameters of the gas reservoir, production dynamic data, water volume change rate, and rock pore volume change rate.

[0053] Among them, the equivalent apparent pressure is the conversion of the pressure within the entire gas reservoir into an apparent pressure when considering the changes in rock volume and water volume. That is, when converting the pressure in the gas reservoir into the equivalent apparent pressure, not only the influence brought about by the decrease in the average formation pressure due to the exploitation of natural gas is considered, but also the influence brought about by the changes in water volume and rock pore volume due to the decrease in the average formation pressure is considered.

[0054] Step S30: Determine the functional relationship between the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir, and determine the original geological reserves of the gas reservoir in the gas reservoir based on the functional relationship.

[0055] When using the above calculation method to calculate the original geological reserves of natural gas in special gas reservoirs such as abnormally high pressure and fractured reservoirs, by obtaining the water volume change rate and rock pore volume change rate, and combining the basic parameters of the gas reservoir and production dynamic data to calculate the equivalent apparent pressure corresponding to the current average formation pressure of the gas reservoir, and by determining the relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir, the original geological reserves of natural gas in this special gas reservoir can be calculated. That is, based on considering the changes in water volume and rock pore volume, the method of the present invention converts the pressure of the entire gas reservoir into an equivalent apparent pressure, and by determining the relationship between the equivalent apparent pressure and the cumulative gas production, the purpose of obtaining a more accurate calculation result when calculating the original geological reserves of special gas reservoirs with abnormally high pressure and fractures is achieved.

[0056] In the embodiment of the present invention, before step S10: obtaining the water volume change rate and rock pore volume change rate, the following steps are further included:

[0057] Step S00: Statistically analyze the basic parameters of the gas reservoir and production dynamic data.

[0058] Among them, the basic parameters of the gas reservoir include the original formation pressure of the gas reservoir, the volume compressibility coefficient of water, the overburden pressure, the original reservoir water saturation, the pore volume compressibility coefficient under zero effective stress, and the attenuation coefficient of pore pressure with the change of effective stress; the production dynamic data includes the current average formation pressure of the gas reservoir, the current gas compressibility factor, and the cumulative gas production of the gas reservoir. The basic parameters of the gas reservoir can be directly measured by instruments during the exploration stage, and the production dynamic data is recorded in real time by instruments during the production process. Therefore, both the basic parameters of the gas reservoir and the production dynamic data are very easy-to-obtain parameters, so there is no need for additional instruments to measure them, which is convenient for statistics.

[0059] Figure 2 Schematically shows a flowchart of step S10 in the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention. As Figure 2 shown, in the embodiment of the present invention, the steps of obtaining the water volume change rate include:

[0060] S101: Statistically analyze the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, and the volume compressibility coefficient of water;

[0061] S102: Calculate the water volume change rate according to the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, and the volume compressibility coefficient of water.

[0062] That is, when calculating the water volume change rate, only the original formation pressure of the gas reservoir and the volume compressibility coefficient of water in the basic parameters of the gas reservoir, and the current average formation pressure of the gas reservoir in the production dynamic data need to be statistically analyzed, and then the water volume change rate corresponding to the current average formation pressure of the gas reservoir can be calculated, which is convenient and fast.

[0063] In the embodiment of the present invention, the calculation formula of the water volume change rate is:

[0064]

[0065] where ε w is the formation water volume change rate, dimensionless; ΔV w is the formation water volume change, with the unit of 10 8 m 3 ; V wi is the original formation water volume, with the unit of 10 8 m 3 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; C w is the volume compressibility coefficient of water, with the unit of MPa -1 .

[0066] Figure 3Another flowchart of step S10 in the evaluation method of the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention is schematically shown. As Figure 3 shown, in the embodiment of the present invention, obtaining the change rate of rock pore volume includes:

[0067] S103: Statistically analyze the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility under zero effective stress, and the attenuation coefficient of pore pressure with the change of effective stress;

[0068] S104: Calculate the change rate of rock pore volume according to the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility under zero effective stress, and the attenuation coefficient of pore pressure with the change of effective stress.

[0069] When calculating the change rate of rock pore volume, only the original formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility under zero effective stress, the attenuation coefficient of pore pressure with the change of effective stress in the basic parameters of the gas reservoir reservoir, and the current average formation pressure in the production dynamic data need to be statistically analyzed, and then the change rate of rock pore volume corresponding to the current average formation pressure of the gas reservoir can be calculated, which is convenient and fast. It should be particularly noted that in the embodiment of the present invention, steps S101 to S102 can be executed first, steps S103 to S104 can be executed first, or both can be executed simultaneously.

[0070] In the embodiment of the present invention, when considering the change of pore volume compressibility, the calculation formula of the change rate of rock pore volume is:

[0071]

[0072] where ε pv is the change rate of rock pore volume, dimensionless; ΔV p is the change amount of rock pore volume, with the unit of 10 8 m 3 ; V pi is the original rock pore volume, with the unit of 10 8 m 3 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; p ob is the overburden pressure, with the unit of MPa; C p0 is the pore volume compressibility under zero effective stress, with the unit of MPa -1 ; γ is the attenuation coefficient of pore pressure with the change of effective stress, dimensionless.

[0073] For some fractured gas reservoirs with abnormally high pressure, since the compressibility of rock pore volume varies greatly during the exploitation process, the rock pore volume does not change uniformly with pressure. At this time, by considering the influence brought by the change of pore volume compressibility, the final calculation result can be made more accurate.

[0074] In the embodiment of the present invention, when not considering the change of pore volume compressibility, the calculation formula of the change rate of rock pore volume is:

[0075]

[0076] Among them,

[0077]

[0078] Among them, ε pc is the change rate of rock pore volume, dimensionless; C pi is the original pore volume compressibility of the rock, with the unit of MPa -1 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; p ob is the overburden pressure, with the unit of MPa; C p0 is the pore volume compressibility under zero effective stress, with the unit of MPa -1 ; γ is the attenuation coefficient of pore pressure with respect to effective stress change, dimensionless.

[0079] For some ordinary fractured gas reservoirs, during the exploitation process, due to the small pore volume compressibility of the rock and the small change in compressibility, that is, the rock pore volume can be regarded as changing uniformly with pressure, so the influence brought by the change of pore volume compressibility can be ignored, and the difference between the final calculation result and the calculation result considering the change of pore volume compressibility is not very large. At the same time, since there is no need to consider the change of pore volume compressibility, the calculation process is simplified and it is more convenient for calculation.

[0080] In the embodiment of the present invention, the calculation formula of the equivalent apparent pressure is:

[0081]

[0082] Among them, Y is the equivalent apparent pressure, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; Z is the current gas compressibility factor, dimensionless; S wi is the original reservoir water saturation, fraction; ε w is the change rate of formation water volume, dimensionless; ε p is the change rate of rock pore volume, dimensionless; when considering the change of rock pore volume compressibility, ε p = ε pv, when ignoring the change in the compressibility of the rock pore volume, ε p = ε pc .

[0083] Figure 4 Schematically shows a flowchart of step S30 in the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to an embodiment of the present invention, as Figure 4 shown. In the embodiment of the present invention, the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir is determined according to the values of the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir, including:

[0084] S301: Calculate the values of multiple groups of equivalent apparent pressures and statistically count the values of the corresponding cumulative gas production of the gas reservoir;

[0085] S302: Determine the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir by curve fitting according to the values of multiple groups of equivalent apparent pressures and the corresponding cumulative gas production of the gas reservoir.

[0086] That is, the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir is determined by the method of curve fitting, which is more intuitive and convenient.

[0087] In the embodiment of the present invention, the curve fitting can be linear fitting. Therefore, the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir is a linear function. That is, the linear function of the equivalent apparent pressure varying with the cumulative gas production of the gas reservoir is determined by linear fitting, which is not only easy to implement modeling on a computer, but also can ensure the accuracy of the calculation results through linear fitting. Of course, other forms of curve fitting can also exist between the equivalent apparent pressure and the cumulative gas production of the gas reservoir.

[0088] In the embodiment of the present invention, determining the original geological reserves of natural gas in the gas reservoir according to the linear function includes:

[0089] Calculate the intercept and slope of the linear function;

[0090] Calculate the original geological reserves of natural gas in the gas reservoir according to the intercept and slope of the linear function; the calculation formula for the original geological reserves of natural gas in the gas reservoir is:

[0091]

[0092] where G is the original geological reserves of natural gas in the gas reservoir, a is the absolute value of the slope, and b is the intercept.

[0093] The following describes the evaluation process of the method for evaluating the original geological reserves of natural gas in a fractured gas reservoir of the present invention with reference to Example 1. It should be noted that the data in Example 1 are only for illustrative purposes and do not constitute a limitation.

[0094] Example 1

[0095] 1. Statistically analyze the basic parameters of the gas reservoir reservoir and production performance data. The basic parameters of the gas reservoir reservoir and production performance data are shown in Table 1 and Table 2.

[0096] Table 1: Basic parameters of the gas reservoir reservoir

[0097]

[0098]

[0099] Table 2: Production performance data

[0100]

[0101] 2. Calculate the formation water volume change rate

[0102] Substitute the volume compressibility coefficient C of water w , the original formation pressure p i , and the average formation pressure p of the gas reservoir into the formula:

[0103]

[0104] Obtain the data of the water body and change rate corresponding to the current average formation pressure of the gas reservoir. The specific data are shown in Table 3.

[0105] Table 3: Water body and change rate corresponding to the current average formation pressure of the gas reservoir

[0106]

[0107] 3. Calculate the rock pore volume change rate

[0108] Substitute the original formation pressure p i , the average formation pressure p of the gas reservoir, the pore volume compressibility coefficient C under zero effective stress p0 , the overburden pressure p ob , and the attenuation coefficient γ of pore pressure with respect to effective stress into the formula

[0109] ;

[0110] Calculate the rock pore volume change rate at the current average formation pressure of the gas reservoir considering the change of rock pore volume compressibility coefficient. The specific data are shown in Table 4.

[0111] Table 4: Rock pore volume change rate at the current average formation pressure of the gas reservoir considering the change of rock pore volume compressibility coefficient

[0112]

[0113] 4. Calculate the equivalent apparent pressure at the current average formation pressure of the gas reservoir

[0114] Substitute the original reservoir water saturation S wi , the average formation pressure p of the gas reservoir, the current gas compressibility factor Z, the formation water volume change rate ε w and the rock pore volume change rate ε p into the formula

[0115] , where ε p = ε pv ;

[0116] Then list the corresponding equivalent apparent pressure Y and the corresponding cumulative gas production G p at the currently calculated average formation pressure of the gas reservoir in Table 5, and the specific data are shown in Table 5.

[0117] Table 5: Equivalent apparent pressure and corresponding cumulative gas production

[0118] <![CDATA[G p / 10 8 m 3 > Y / MPa 0 45.53161111 0.11114 44.86495397 0.465005 43.79428799 0.913418 42.74867001 1.206347 41.93532569 1.558371 40.90972506 2.134488 39.60465619 2.477423 38.96519977 2.975813 37.59623246 3.32965 36.61711662 3.62139 35.98489594 4.88805 33.14621526 6.481759 28.26707793 7.969425 26.31181386 9.221587 23.39373457 10.42592 20.68876405

[0119] According to Table 5, with the cumulative gas production G p as the horizontal axis and the equivalent apparent pressure Y as the vertical axis, plot the relationship diagram of G p versus Y, and fit the scatter points into a straight line according to the relationship diagram. The fitting result is as Figure 5 shown.

[0120] As Figure 5 , the fitting straight line relationship formula obtained from the calculated data is:

[0121] Y = -2.0986G p + 44.8429.

[0122] 5. Calculate the original in - place gas reserves of the gas reservoir

[0123] Obtain the Y - intercept b of the straight line b = 44.8429 (MPa), and the absolute value of the slope of the straight line a = 2.0986 (MPa / (10 8 m 3 ³)). Apply Equation (6) to calculate the original in - place gas reserves of this gas reservoir considering the change of the rock pore volume compressibility:

[0124]

[0125] In the description of the present invention, it should be understood that the terms "first" and "second" are used for descriptive purposes only and cannot be construed as indicating or implying relative importance or implicitly specifying the quantity of the indicated technical features. Thus, features defined with "first" and "second" may explicitly or implicitly include at least one such feature. In the description of the present invention, "a plurality" means at least two, such as two, three, etc., unless otherwise specifically defined.

[0126] In the present invention, unless otherwise clearly specified and defined, terms such as "mounted", "connected", "coupled", "fixed", etc. shall be construed in a broad sense. For example, it may be a fixed connection, a detachable connection, or integrated; it may be a mechanical connection, an electrical connection, or communicable with each other; it may be directly connected, or indirectly connected through an intermediate medium, and it may be the internal communication of two components or the interaction relationship between two components, unless otherwise clearly defined. For those of ordinary skill in the art, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0127] In the description of this specification, the description with reference to terms such as "one embodiment", "some embodiments", "example", "specific example", or "some examples" means that the specific features, structures, materials, or characteristics described in connection with the embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic descriptions of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials, or characteristics described can be combined in a suitable manner in any one or more embodiments or examples. In addition, without contradiction, those skilled in the art can combine and combine the different embodiments or examples described in this specification and the features of different embodiments or examples.

[0128] Although the embodiments of the present invention have been shown and described above, it can be understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those of ordinary skill in the art can make changes, modifications, substitutions, and variations to the above embodiments within the scope of the present invention.

Claims

1. A method for evaluating the original geological reserves of natural gas in a fractured gas reservoir, characterized in that, the method for evaluating the original geological reserves of natural gas in the fractured gas reservoir includes: Obtaining the water volume change rate and the rock pore volume change rate; Calculating the equivalent apparent pressure according to the basic parameters of the gas reservoir reservoir, production dynamic data, the water volume change rate and the rock pore volume change rate; Determining the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir according to the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir, and determining the original geological reserves of natural gas in the gas reservoir according to the functional relationship; The basic parameters of the gas reservoir reservoir include the original formation pressure of the gas reservoir, the volume compressibility of water, the overburden pressure, the original reservoir water saturation, the pore volume compressibility under zero effective stress, and the attenuation coefficient of pore pressure with the change of effective stress. The production dynamic data includes the current average formation pressure of the gas reservoir, the current gas compressibility factor, and the cumulative gas production of the gas reservoir; The calculation formula for the equivalent apparent pressure is: When the gas reservoir type is an abnormally high-pressure fractured gas reservoir, the calculation formula for the rock pore volume change rate is: When the gas reservoir type is a common fractured gas reservoir that is not abnormally high-pressure, the calculation formula for the rock pore volume change rate is: Wherein, Among them, Y is the equivalent apparent pressure, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; Z is the current gas compressibility factor, dimensionless; S wi is the initial water saturation of the reservoir, in fraction; ε w is the formation water volume change rate, dimensionless; ε p is the rock pore volume change rate, dimensionless; ε pv and ε pc are respectively the rock pore volume change rates referred to two types of gas reservoirs, dimensionless; ΔV p is the rock pore volume change amount, with the unit of 10 8 m 3 ; V pi is the initial rock pore volume, with the unit of 10 8 m 3 ; p i is the initial formation pressure of the gas reservoir, with the unit of MPa; with the unit of MPa; p ob is the overburden pressure, with the unit of MPa; C p0 is the pore volume compressibility coefficient under zero effective stress, with the unit of MPa -1 ; γ is the attenuation coefficient of pore pressure with respect to effective stress change, dimensionless; C pi is the initial rock pore volume compressibility coefficient, with the unit of MPa -1 .

2. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to claim 1, characterized in that, Before obtaining the water volume change rate and the rock pore volume change rate, it further includes: Statistical basic parameters of the gas reservoir reservoir and the production dynamic data.

3. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to claim 2, characterized in that, Obtaining the water volume change rate includes: Statistical original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, and the volume compressibility of water; Calculating the water volume change rate according to the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, and the volume compressibility of water; The calculation formula for the water volume change rate is: Among them, ε w is the formation water volume change rate, dimensionless; ΔV w is the formation water volume change, with the unit of 10 8 m 3 ; V wi is the original formation water volume, with the unit of 10 8 m 3 ; p i is the original formation pressure of the gas reservoir, with the unit of MPa; p is the current average formation pressure of the gas reservoir, with the unit of MPa; C w is the volume compressibility of water, with the unit of MPa -1 .

4. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to claim 2, characterized in that, Obtaining the rock pore volume change rate includes: Statistical original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility under zero effective stress, and the attenuation coefficient of pore pressure with the change of effective stress; Calculating the rock pore volume change rate according to the original formation pressure of the gas reservoir, the current average formation pressure of the gas reservoir, the overburden pressure, the pore volume compressibility under zero effective stress, and the attenuation coefficient of pore pressure with the change of effective stress.

5. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to any one of claims 1 to 4, characterized in that, Determining the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir according to the equivalent apparent pressure and the corresponding cumulative gas production of the gas reservoir includes: Calculating multiple sets of values of the equivalent apparent pressure and statistical values of the corresponding cumulative gas production of the gas reservoir; The functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir is determined by curve fitting according to multiple groups of the values of the equivalent apparent pressure and the corresponding values of the cumulative gas production of the gas reservoir.

6. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to claim 5, wherein, the curve fitting is linear fitting, and the functional relationship between the equivalent apparent pressure and the cumulative gas production of the gas reservoir is a linear function.

7. The method for evaluating the original geological reserves of natural gas in a fractured gas reservoir according to claim 6, wherein, determining the original geological reserves of natural gas in the gas reservoir according to the linear function includes: calculating the intercept and slope of the linear function; calculating the original geological reserves of natural gas in the gas reservoir according to the intercept and the slope of the linear function; the calculation formula for the original geological reserves of natural gas in the gas reservoir is: where G is the original geological reserves of natural gas in the gas reservoir, a is the absolute value of the slope, and b is the intercept.

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