Method for predicting deep coalbed methane recovery rate

Abstract

The present invention discloses a method for predicting the recovery rate of deep coalbed methane, comprising: determining correction values ​​of physical parameters, capillary pressure, reservoir porosity and water saturation, as well as average coal reservoir pressure, cumulative water production and conventional average deviation coefficient of gas under multiple production dates, calculating the actual average deviation coefficient of gas, establishing a prediction model for reservoir gas production, calculating an iterative value of a control volume according to the correction values ​​of physical parameters, capillary pressure, reservoir porosity and water saturation and original gas reserves of the reservoir, returning the iterative value to an initial given value that replaces the control volume for cyclic calculation, determining a first relationship model between cumulative water production and average coal reservoir pressure, determining a vertical axis prediction value of the prediction model under a given exhaust gas pressure according to the first relationship model, substituting the vertical axis prediction value into the prediction model established last time in the cyclic calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate, thereby achieving the purpose of improving the reliability of the prediction.

Description

Technical Field

[0001] The invention belongs to the technical field of coalbed methane development, and in particular relates to a method for predicting deep coalbed methane recovery rate. Background Art

[0002] Coalbed methane, commonly known as "gas," is an unconventional natural gas associated with coal, mostly stored in an adsorbed state within coal seams. Deep coalbed methane refers to natural gas stored in coal seams buried at depths exceeding 1,500 meters. It contains not only adsorbed gas but also free and dissolved gas. However, the recovery rate of deep coalbed methane is unknown, and prediction methods are lacking. Accurately predicting coalbed methane recovery rates has theoretical guidance for comparative evaluation of the effectiveness of individual well development under different production methods, optimizing methods for improving coalbed methane recovery, and ultimately achieving efficient deep coalbed methane development.

[0003] Currently, most deep coalbed methane (CBM) recoverable reserves and recovery rate prediction methods are empirical and based on the principle of production decline. However, deep coalbed methane exhibits adsorption and desorption characteristics, and conventional decline analysis methods do not consider the effects of adsorption and desorption. This method is suitable for deep CBM wells in the production decline phase, but not for those in the production ramp-up or stable production phases, resulting in low prediction reliability. Summary of the Invention

[0004] In view of the above-mentioned defects or deficiencies of the prior art, the present invention provides a deep coalbed methane recovery rate prediction method, which aims to solve the technical problem that the existing recovery rate prediction method has low prediction reliability due to its principle of production decline.

[0005] In order to achieve the above object, the present invention provides a method for predicting the recovery rate of deep coalbed methane, wherein the method for predicting the recovery rate of deep coalbed methane includes:

[0006] Determine the physical properties of the reservoir and fluid respectively;

[0007] Determine the average coal reservoir pressure, cumulative gas production and cumulative water production under multiple production dates, and determine the gas conventional average deviation coefficient based on the average coal reservoir pressure;

[0008] Determine the capillary pressure between the micropores and mesopores of the reservoir;

[0009] According to the initial given value of the control volume, the correction values ​​of the reservoir porosity and water saturation after fracturing flowback and before production are determined respectively;

[0010] Calculate the actual average deviation coefficient of gas based on the physical properties, capillary pressure, initial given values ​​of control volume, corrected values ​​of reservoir porosity and water saturation, average coal reservoir pressure under multiple production dates, cumulative water production, and conventional average deviation coefficient of gas;

[0011] A prediction model for reservoir gas production is established with the cumulative gas production as the horizontal axis and the ratio of the average coal reservoir pressure to the actual average deviation coefficient of gas as the vertical axis, and the original gas reserves of the reservoir are determined based on the prediction model for reservoir gas production.

[0012] An iterative value of the control volume is calculated based on the corrected values ​​of the physical parameters, capillary pressure, reservoir porosity and water saturation, and the original gas reserves of the reservoir, and the iterative value is returned to replace the initial given value of the control volume for cyclic calculation until the difference between the iterative values ​​of the control volume calculated two consecutive times is less than a preset value, and the cycle stops;

[0013] Determining a first relationship model between cumulative water production and average coal reservoir pressure, and determining a vertical axis prediction value of a prediction model under a given exhaust gas pressure based on the first relationship model;

[0014] Substitute the predicted value on the vertical axis into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate.

[0015] In one embodiment of the present invention, the actual average deviation coefficient of gas is calculated based on the physical parameters, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, and average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas under multiple production dates, including:

[0016] Substitute the physical properties, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas into the sixth calculation formula to calculate the actual average deviation coefficient of gas under multiple production dates. The sixth calculation formula is:

[0017]

[0018] Where Z* is the actual average deviation coefficient of the gas, dimensionless; ρ c is the coal rock density, t / m 3 ; V L is the Langmuir volume, m 3 / t;p L is the Langmuir pressure, MPa; p c is the capillary pressure between the micropores and mesopores of the reservoir, MPa; φ ip is the corrected value of reservoir porosity, decimal; S wip is the corrected value of water saturation, decimal; Z sc is the natural gas deviation coefficient under standard conditions, dimensionless, and its value is 1; T sc is the temperature under standard conditions, K, with a value of 293.15; p i is the original coal reservoir pressure, MPa; psc is the pressure under standard conditions, MPa, with a value of 0.101325; T is the coal reservoir temperature, K; p is the average coal reservoir pressure, MPa; Z is the conventional average deviation coefficient of gas, dimensionless; C p is the pore compression coefficient, MPa -1 ; C w is the isothermal compressibility of water, MPa -1 ; C s is the solubility coefficient of coalbed methane in water, MPa -1 ; C a W is the coal matrix shrinkage coefficient, dimensionless; e is the cumulative water intrusion, (10 6 m 3 ), take 0; W p is the cumulative water production, (10 6 m 3 );B w is the volume coefficient of water, m 3 / m 3 , takes the value as 1; V is the initial given value of the control volume, (10 6 m 3 ).

[0019] In one embodiment of the present invention, determining a first relationship model between cumulative water production and average coal reservoir pressure, and determining a vertical axis prediction value of a prediction model under a given exhaust gas pressure based on the first relationship model includes:

[0020] Substitute the cumulative water production and average coal reservoir pressure corresponding to the last production date, the iterative value of the control volume obtained in the last cycle calculation, and the corrected values ​​of the reservoir porosity and water saturation into the tenth calculation formula to obtain the first relationship model, where the tenth calculation formula is:

[0021]

[0022] Where W p is the cumulative water production, (10 6 m 3 ); p is the average coal reservoir pressure, MPa; W ps is the cumulative water production corresponding to the last production date, (10 6 m 3 );p s is the average coal reservoir pressure corresponding to the last production date, MPa; V is the iterative value of the control volume obtained in the last cycle calculation, (10 6 m 3 );φ ip The last corrected value of reservoir porosity obtained in the cycle calculation, decimal; S wipThe last corrected value of water saturation obtained in the cycle calculation, decimal; R w is the water recovery factor, which is taken as 35%;

[0023] The vertical axis prediction value of the prediction model at a given exhaust gas pressure is determined according to the first relationship model.

[0024] In one embodiment of the present invention, determining the vertical axis prediction value of the prediction model at a given exhaust gas pressure according to the first relationship model includes:

[0025] Substituting a given exhaust gas pressure as the average coal reservoir pressure into the first relationship model to calculate the cumulative water production under the given exhaust gas pressure;

[0026] Substituting the given exhaust gas pressure as the average coal reservoir pressure and the cumulative water production under the given exhaust gas pressure into the sixth calculation formula to obtain the actual average deviation coefficient of the gas under the given exhaust gas pressure;

[0027] The ratio of the given exhaust gas pressure to the actual average deviation coefficient of the gas at the given exhaust gas pressure is determined as the vertical axis prediction value of the prediction model at the given exhaust gas pressure.

[0028] In one embodiment of the present invention, determining the vertical axis prediction value of the prediction model at a given exhaust gas pressure according to the first relationship model includes:

[0029] Substituting a given pressure value lower than the average coal reservoir pressure corresponding to the last production date as the average coal reservoir pressure into the first relationship model to calculate the cumulative water production under the given pressure value;

[0030] Substituting the given pressure value and the cumulative water production at the given pressure value into the sixth calculation formula to obtain the actual average deviation coefficient of the gas at the given pressure value;

[0031] A second relationship model is established with a given pressure value as the average coal reservoir pressure as the horizontal axis and a ratio of the given pressure value to the actual average deviation coefficient of gas at the given pressure value as the vertical axis;

[0032] Substitute the given exhaust gas pressure as the average coal reservoir pressure into the second relationship model to obtain the vertical axis prediction value of the prediction model under the given exhaust gas pressure.

[0033] In one embodiment of the present invention, determining the capillary pressure between the micropores and mesopores of the reservoir includes:

[0034] The capillary pressure between the micropores and mesopores of the reservoir is determined according to the first calculation formula, wherein the first calculation formula is:

[0035]

[0036] Where p cis the capillary pressure between the micropores and mesopores of the reservoir, MPa; d is the average pore size of the coal matrix micropores, nm; D is the average pore size of the coal matrix mesopores, nm; σ gw is the gas-water interfacial tension, mN / m; θ is the wetting angle of the coal matrix surface, degrees.

[0037] In one embodiment of the present invention, determining the corrected values ​​of reservoir porosity and water saturation after fracturing flowback and before production based on the initial given value of the control volume includes:

[0038] Substitute the initial given value of the control volume into the fourth and fifth calculation formulas respectively to calculate the corrected value of the reservoir porosity and the corrected value of the water saturation after fracturing flowback and before production. The fourth calculation formula is:

[0039]

[0040] Where, φ ip is the corrected value of reservoir porosity, decimal; φ i is the original porosity of the coal reservoir, decimal; W fin is the net injection volume of fracturing, (10 6 m 3 );B w is the volume coefficient of water, m 3 / m 3 , takes the value as 1; V is the initial given value of the control volume, (10 6 m 3 );

[0041] The fifth calculation formula is:

[0042]

[0043] Where S wip is the correction value of water saturation, decimal; φ i is the original porosity of the coal reservoir, decimal; W fin is the net injection volume of fracturing, (10 6 m 3 );B w is the volume coefficient of water, m 3 / m 3 , takes the value as 1; φ ip is the corrected value of reservoir porosity, decimal.

[0044] In one embodiment of the present invention, before respectively determining the corrected values ​​of the reservoir porosity and water saturation after fracturing flowback and before production based on the initially given values ​​of the control volumes, the method further includes:

[0045] Substitute the total fracturing fluid volume during the fracturing process and the cumulative flowback volume during the flowback process into the third calculation formula to calculate the net fracturing injection volume, where the third calculation formula is:

[0046] W fin =W fi -W fp ;

[0047] Where W fin is the net injection volume of fracturing, (10 6 m 3 );W fi is the total amount of fracturing fluid during the fracturing process, (10 6 m 3 );W fp is the cumulative flowback volume during the flowback process, (10 6 m 3 ).

[0048] In one embodiment of the present invention, calculating an iterative value of the control volume based on the physical parameters, capillary pressure, corrected values ​​of reservoir porosity and water saturation, and original gas reserves of the reservoir, and returning the iterative value to replace the initial given value of the control volume for cyclic calculation until the difference between two consecutive iterative values ​​of the control volume calculated is less than a preset value, and the cycle is stopped, includes:

[0049] Substitute the corrected values ​​of the physical properties, capillary pressure, reservoir porosity and water saturation, and the original gas reserves of the reservoir into the eighth calculation formula to calculate the iterative value of the control volume, where the eighth calculation formula is:

[0050]

[0051] Where V is the iterative value of the control volume, (10 6 m 3 );G i is the original gas reserves of the reservoir, (10 6 m 3 );ρ c is the coal rock density, t / m 3 ; V L is the Langmuir volume, m 3 / t;p L is the Langmuir pressure, MPa; p c is the capillary pressure between the micropores and mesopores of the reservoir, MPa; φ ip is the corrected value of reservoir porosity, decimal; S wip is the corrected value of water saturation, decimal; Z sc is the natural gas deviation coefficient under standard conditions, dimensionless, and its value is 1; T scis the temperature under standard conditions, K, with a value of 293.15; p sc is the pressure under standard conditions, MPa, with a value of 0.101325; p i is the original coal reservoir pressure, MPa; T is the coal reservoir temperature, K; Z i is the deviation coefficient of gas at the original coal reservoir pressure, dimensionless; C s is the solubility coefficient of coalbed methane in water, MPa -1 ;

[0052] The iteration value is returned to replace the initial given value of the control volume for cyclic calculation until the difference between the iteration values ​​of the control volume calculated twice is less than the preset value and the cycle is stopped.

[0053] In one embodiment of the present invention, substituting the vertical axis prediction value into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate includes:

[0054] Substitute the predicted value on the vertical axis into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane;

[0055] Substitute the recoverable reserves and the original gas reserves of the reservoir obtained in the last cycle calculation into the twelfth calculation formula to calculate the coalbed methane recovery rate, where the twelfth calculation formula is:

[0056]

[0057] Where R cbm is the recovery rate of coalbed methane; G pab is the recoverable reserves of coalbed methane, (10 6 m 3 );G i is the original gas reserves of the reservoir, (10 6 m 3 ).

[0058] Through the above technical solution, the deep coalbed methane recovery rate prediction method provided by the embodiment of the present invention has the following beneficial effects:

[0059] In the above technical scheme, the physical properties of the reservoir and fluid, the capillary pressure between the micropores and mesopores of the reservoir, the initial given value of the control volume, the corrected values ​​of the reservoir porosity and water saturation after fracturing and before production, and the average coal reservoir pressure, cumulative water production and conventional average deviation coefficient of gas under multiple production dates are first determined, and the actual average deviation coefficient of gas is calculated based on the above parameters. Then, a prediction model for reservoir gas production is established with the cumulative gas production as the horizontal axis and the ratio of the average coal reservoir pressure to the actual average deviation coefficient of gas as the vertical axis, and the original gas reserves of the reservoir are determined based on the prediction model for reservoir gas production. Then, the iterative value of the control volume is calculated based on the physical properties, capillary pressure, the corrected values ​​of the reservoir porosity and water saturation, and the original gas reserves of the reservoir, and the iterative value is returned to the initial given value that replaces the control volume for cyclic calculation until the difference between the iterative values ​​of the control volume calculated twice is less than the preset value, and the cycle is stopped. Then the cumulative water production and the average water production are determined. The first relationship model between the average coal reservoir pressure is established, and the vertical axis prediction value of the prediction model under a given exhaust gas pressure is determined according to the first relationship model. Finally, the vertical axis prediction value is substituted into the prediction model established for the last time in the cyclic calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate. Since the calculation of the actual average deviation coefficient of gas includes the capillary pressure between the micropores and mesopores of the reservoir, the correction value of the reservoir porosity and water saturation after fracturing and before production, and the physical parameters include the solubility coefficient of coalbed methane in water, the actual average deviation coefficient of gas comprehensively considers the pressure difference between the adsorbed gas pores and the free gas pores, the change of the physical parameters of the coal reservoir due to fracturing transformation, and the influence of dissolved gas. This method is not only applicable to deep coalbed methane wells in the gas production decline period, but also to deep coalbed methane wells in the production increase period and stable production period. It will obviously make the subsequent calculation of recoverable reserves and recovery rate of coalbed methane more accurate, thereby achieving the purpose of improving the reliability of prediction.

[0060] 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

[0061] 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 detailed description, they are used to explain the embodiments of the present invention, but do not constitute a limitation of the embodiments of the present invention. In the accompanying drawings:

[0062] Figure 1 is a flow chart of a method for predicting deep coalbed methane recovery rate according to one embodiment of the present invention;

[0063] Figure 2 is an initial graph of a prediction model for reservoir gas production according to an embodiment of the present invention;

[0064] Figure 3is a final graph of a prediction model for reservoir gas production according to an embodiment of the present invention;

[0065] Figure 4 is W according to one embodiment of the present invention p The first relationship model between p;

[0066] Figure 5 is a second relationship model between p / Z* and p according to an embodiment of the present invention;

[0067] Figure 6 According to one embodiment of the present invention, at different waste pressures p ab The following p ab / Z ab *Schematic diagram of the prediction results;

[0068] Figure 7 According to an embodiment of the present invention, ab / Z ab *Recoverable reserves under G pab Schematic diagram of the prediction results. DETAILED DESCRIPTION

[0069] The following describes the specific implementation of the embodiment of the present invention in detail with reference to the accompanying drawings. It should be understood that the specific implementation described herein 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.

[0070] It should be noted that if the implementation methods of this application involve directional indications (such as up, down, left, right, front, back, etc.), such directional indications are only used to explain the relative position relationship, movement status, etc. between the various components under a certain specific posture (as shown in the accompanying drawings). If the specific posture changes, the directional indication will also change accordingly.

[0071] In addition, if there are descriptions involving "first", "second", etc. in the embodiments of this application, the descriptions of "first", "second", etc. are only for descriptive purposes and cannot be understood as indicating or implying their relative importance or implicitly indicating the number of the indicated technical features. Therefore, the features specified as "first" and "second" may explicitly or implicitly include at least one of such features. In addition, the technical solutions between the various embodiments can be combined with each other, but they must be based on the fact that they can be implemented by ordinary technicians in this field. When the combination of technical solutions is contradictory or cannot be implemented, it should be deemed that such a combination of technical solutions does not exist and is not within the scope of protection required by this application.

[0072] Figure 1 The flowchart of the method for predicting the recovery rate of deep coalbed methane according to one embodiment of the present invention is schematically shown. Figure 1As shown, the present invention provides a method for predicting the recovery rate of deep coalbed methane, wherein the method for predicting the recovery rate of deep coalbed methane includes the following steps:

[0073] Step S100: determining the physical parameters of the reservoir and the fluid respectively.

[0074] Specifically, the physical parameters of the reservoir and the physical parameters of the fluid are sorted and counted. The physical parameters of the reservoir include: coal rock density ρ c , coal reservoir original porosity φ i , original coal reservoir pressure p i , coal reservoir temperature T, coal reservoir initial water saturation S wi , pore compression coefficient C p , the average pore size d of the coal matrix micropores, the average pore size D of the coal matrix mesopores, the coal matrix surface wetting angle θ, the coal matrix shrinkage coefficient C a , Langmuir volume of adsorbed gas V L , adsorbed gas Langmuir pressure p L The physical parameters of the fluid include the relative density of the gas γ g , gas deviation coefficient Z at original coal reservoir pressure i , volume coefficient of water B w , isothermal compressibility coefficient of water C w , the solubility coefficient of coalbed methane in water C s , air-water interfacial tension σ gw .

[0075] Step S200: determining the average coal reservoir pressure, cumulative gas production and cumulative water production under multiple production dates, and determining the gas conventional average deviation coefficient based on the average coal reservoir pressure.

[0076] Furthermore, the average coal reservoir pressure, cumulative gas production, and cumulative water production under multiple production dates are sorted and counted according to the production date. Of course, the cumulative water intrusion during the production process is generally 0. At the same time, the conventional average deviation coefficient of gas can also be determined based on the average coal reservoir pressure. Specifically, the Dranchuk-Abou-Kassem method is used to calculate the gas relative density γ g and reservoir temperature T, we can obtain the conventional average gas deviation coefficient at the average coal reservoir pressure corresponding to each production date. It should be noted that the measured average coal reservoir pressure generally detects the pressure within larger pores (such as cleats, macropores, and mesopores). Therefore, the conventional average gas deviation coefficient determined based on the average coal reservoir pressure also primarily represents larger pores, ignoring micropores.

[0077] Step S300: determining the capillary pressure between the micropores and mesopores of the reservoir.

[0078] Specifically, deep coalbed methane adsorbed gas is primarily stored in the micropores (pore diameter less than 2 nm) of the coal matrix, while free gas, dissolved gas, and water are stored in cleats (pore diameter greater than 1000 nm), macropores (pore diameter between 50 nm and 1000 nm), and mesopores (pore diameter between 2 nm and 50 nm). The original coal reservoir pressure is actually the pressure within the cleats, macropores, and mesopores of the coal reservoir. To subsequently calculate the actual average deviation coefficient of gas representing all pores, the capillary pressure between the micropores and mesopores of the reservoir can be determined.

[0079] In one embodiment of the present invention, step S300 of determining the capillary pressure between the micropores and mesopores of the reservoir includes:

[0080] The capillary pressure between the micropores and mesopores of the reservoir is determined according to the first calculation formula, wherein the first calculation formula is:

[0081]

[0082] Where p c is the capillary pressure between the micropores and mesopores of the reservoir, MPa; d is the average pore size of the coal matrix micropores, nm; D is the average pore size of the coal matrix mesopores, nm; σ gw is the gas-water interfacial tension, mN / m; θ is the wetting angle of the coal matrix surface, degrees.

[0083] More specifically, the parameter in the formula is divided by p c All other physical parameters are known, from which the capillary pressure can be calculated. i In the case of , the original pressure p in the micropores of the coal reservoir can also be calculated according to the second calculation formula mi , the second calculation formula is:

[0084] p mi =p i +p c

[0085] Where p mi is the original pressure in the micropores of the coal reservoir, MPa; p i is the original coal reservoir pressure, MPa; p c is the capillary pressure between micropores and mesopores in coal reservoir, MPa.

[0086] Step S400: determining the corrected values ​​of the reservoir porosity and water saturation after fracturing flowback and before production according to the initially given value of the control volume.

[0087] Specifically, calculation formulas for the corrected values ​​of reservoir porosity and water saturation after fracturing flowback and before production are established based on the initial given value of the control volume. The corrected values ​​of reservoir porosity and water saturation can be calculated by substituting the initial given value of the control volume and other known parameters into the calculation formula.

[0088] In one embodiment of the present invention, before respectively determining the corrected values ​​of the reservoir porosity and water saturation after fracturing flowback and before production based on the initially given values ​​of the control volumes, the method further includes:

[0089] Substitute the total fracturing fluid volume during the fracturing process and the cumulative flowback volume during the flowback process into the third calculation formula to calculate the net fracturing injection volume, where the third calculation formula is:

[0090] W fin =W fi -W fp ;

[0091] Where W fin is the net injection volume of fracturing, (10 6 m 3 );W fi is the total amount of fracturing fluid during the fracturing process, (10 6 m 3 );W fp is the cumulative flowback volume during the flowback process, (10 6 m 3 ).

[0092] More specifically, the total fracturing fluid volume during the fracturing process and the cumulative flowback volume during the flowback process can be obtained by performing statistics.

[0093] In one embodiment of the present invention, step S400, determining the corrected values ​​of reservoir porosity and water saturation after fracturing flowback and before production based on the initial given value of the control volume, includes:

[0094] Substitute the initial given value of the control volume into the fourth and fifth calculation formulas respectively to calculate the corrected value of the reservoir porosity and the corrected value of the water saturation after fracturing flowback and before production. The fourth calculation formula is:

[0095]

[0096] Where, φ ip is the corrected value of reservoir porosity, decimal; φ i is the original porosity of the coal reservoir, decimal; W fin is the net injection volume of fracturing, (10 6 m 3 );B w is the volume coefficient of water, m3 / m 3 , takes the value as 1; V is the initial given value of the control volume, (10 6 m 3 );

[0097] The fifth calculation formula is:

[0098]

[0099] Where S wip is the correction value of water saturation, decimal; φ i is the original porosity of the coal reservoir, decimal; W fin is the net injection volume of fracturing, (10 6 m 3 );B w is the volume coefficient of water, m 3 / m 3 , takes the value as 1; φ ip is the corrected value of reservoir porosity, decimal.

[0100] More specifically, the initial given value of the control volume can be given according to geological knowledge, and can be specifically equal to the product of the horizontal well section length of the coalbed methane well, the horizontal well spacing and the thickness of the deep coal reservoir. ip and S wip Both are obtained by considering the impact of fracturing on reservoir porosity and water saturation.

[0101] Step S500, calculating the actual average deviation coefficient of gas based on the physical parameters, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, and the average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas under multiple production dates.

[0102] Specifically, a calculation formula for the actual average deviation coefficient of gas can be designed based on the material balance principle of deep coalbed methane reservoirs, and the calculation formula includes the physical parameters, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation obtained in the above steps, and the average coal reservoir pressure, cumulative water production and conventional average deviation coefficient of gas under multiple production dates. In particular, the physical parameters include the solubility coefficient of coalbed methane in water, so that the actual average deviation coefficient of gas comprehensively considers the pressure difference between adsorbed gas pores and free gas pores, the impact of fracturing transformation on changes in coal reservoir physical parameters and dissolved gas. Compared with the conventional average deviation coefficient of gas, it will obviously make subsequent calculations more accurate.

[0103] In one embodiment of the present invention, step S500, calculating the actual average deviation coefficient of gas based on the physical parameters, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, and average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas under multiple production dates, includes:

[0104] Substitute the physical properties, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas into the sixth calculation formula to calculate the actual average deviation coefficient of gas under multiple production dates. The sixth calculation formula is:

[0105]

[0106] Where Z* is the actual average deviation coefficient of the gas, dimensionless; ρ c is the coal rock density, t / m 3 ; V L is the Langmuir volume, m 3 / t;p L is the Langmuir pressure, MPa; p c is the capillary pressure between the micropores and mesopores of the reservoir, MPa; φ ip is the corrected value of reservoir porosity, decimal; S wip is the corrected value of water saturation, decimal; Z sc is the natural gas deviation coefficient under standard conditions, dimensionless, and its value is 1; T sc is the temperature under standard conditions, K, with a value of 293.15; p i is the original coal reservoir pressure, MPa; p sc is the pressure under standard conditions, MPa, with a value of 0.101325; T is the coal reservoir temperature, K; p is the average coal reservoir pressure, MPa; Z is the conventional average deviation coefficient of gas, dimensionless; C p is the pore compression coefficient, MPa -1 ; C w is the isothermal compressibility of water, MPa -1 ; C s is the solubility coefficient of coalbed methane in water, MPa -1 ; C a W is the coal matrix shrinkage coefficient, dimensionless; e is the cumulative water intrusion, (10 6 m 3 ), take 0; W p is the cumulative water production, (10 6 m 3 );B w is the volume coefficient of water, m 3 / m3 , takes the value as 1; V is the initial given value of the control volume, (10 6 m 3 ).

[0107] Step S600: establishing a reservoir gas production prediction model with the cumulative gas production as the horizontal axis and the ratio of the average coal reservoir pressure to the actual average deviation coefficient of the gas as the vertical axis, and determining the reservoir original gas reserves based on the reservoir gas production prediction model.

[0108] Specifically, the cumulative gas production G under multiple production dates p With the ratio of p / Z* as the horizontal axis and the ratio of p / Z* as the vertical axis, a scatter plot is drawn on the rectangular coordinate graph. Using linear fitting, the slope value of the linear trend line -M and the Y-axis intercept value N can be obtained. The original gas reserves of the deep coalbed methane reservoir can be calculated according to the seventh calculation formula. This value is only the initial value. After subsequent iterative calculations, the final value of the original gas reserves of the reservoir can be obtained. The seventh calculation formula is:

[0109] Step S700, calculate the iterative value of the control volume based on the physical parameters, capillary pressure, the corrected values ​​of the reservoir porosity and water saturation, and the original gas reserves of the reservoir, and return the iterative value to replace the initial given value of the control volume for loop calculation until the difference between the iterative values ​​of the control volume calculated twice is less than the preset value and the loop stops.

[0110] Furthermore, the aforementioned initial given value of the control volume is roughly calculated. To improve the accuracy of the control volume, an iterative calculation method is used, so that an accurate result is approached through repeated calculations. Furthermore, a calculation formula for the iterative value of the control volume can be established based on the physical parameters, capillary pressure, corrected values ​​of reservoir porosity and water saturation, and the original gas reserves of the reservoir. The aforementioned values ​​are substituted into the calculation formula to calculate the iterative value. The first iterative value obtained is then returned to step S400 and replaced with the initial given value in step S400, and the calculation cycle from steps S400 to S700 is repeated. During each calculation cycle, not only the control volume is updated, but also the corrected value of reservoir porosity, corrected value of water saturation, actual gas average deviation coefficient, reservoir gas production prediction model, and original gas reserves are all updated. The cycle is terminated only when the difference between the iterative values ​​of the control volume calculated between two consecutive times is less than a preset value, thereby ensuring the reliability of the final calculation cycle.

[0111] In one embodiment of the present invention, step S700, calculating an iterative value of the control volume based on the physical parameters, capillary pressure, corrected values ​​of reservoir porosity and water saturation, and original gas reserves of the reservoir, and returning the iterative value to replace the initial given value of the control volume for loop calculation until the difference between two consecutive iterative values ​​of the control volume calculated is less than a preset value, and the loop is terminated, includes:

[0112] In step S710, the physical property parameters, capillary pressure, corrected values ​​of reservoir porosity and water saturation, and original gas reserves of the reservoir are substituted into an eighth calculation formula to calculate an iterative value of the control volume. The eighth calculation formula is:

[0113]

[0114] Where V is the iterative value of the control volume, (10 6 m 3 );G i is the original gas reserves of the reservoir, (10 6 m 3 );ρ c is the coal rock density, t / m 3 ; V L is the Langmuir volume, m 3 / t;p L is the Langmuir pressure, MPa; p c is the capillary pressure between the micropores and mesopores of the reservoir, MPa; φ ip is the corrected value of reservoir porosity, decimal; S wip is the corrected value of water saturation, decimal; Z sc is the natural gas deviation coefficient under standard conditions, dimensionless, and its value is 1; T sc is the temperature under standard conditions, K, with a value of 293.15; p sc is the pressure under standard conditions, MPa, with a value of 0.101325; p i is the original coal reservoir pressure, MPa; T is the coal reservoir temperature, K; Z i is the deviation coefficient of gas at the original coal reservoir pressure, dimensionless; C s is the solubility coefficient of coalbed methane in water, MPa -1 ;

[0115] Step S720: Return the iteration value to replace the initial given value of the control volume and perform loop calculation until the difference between the iteration values ​​of the control volume calculated two consecutive times is less than a preset value and the loop stops.

[0116] Specifically, the preset value is 10 -6 (10 6 m 3), the difference between the iteration values ​​of the control volume calculated two times is less than 10 -6 (10 6 m 3 ), the cycle is stopped and the prediction model of the control volume, the original gas reserves of the reservoir and the gas production of the reservoir is finally determined. The final linear trend expression of the prediction model of the gas production of the reservoir can be the ninth calculation formula, which is:

[0117]

[0118] More specifically, M and N in the ninth calculation formula can be obtained in the last cycle of calculation, and p / Z* and G p The linear fitting trend line in the rectangular coordinate diagram is extended to the intersection with the horizontal axis. The value corresponding to the intersection is the original gas reserves of the deep coalbed methane reservoir G i .

[0119] Step S800: determining a first relationship model between the cumulative water production and the average coal reservoir pressure, and determining a vertical axis prediction value of the prediction model under a given exhaust gas pressure based on the first relationship model.

[0120] Furthermore, the prediction model of reservoir gas production is p / Z* and G p According to the sixth calculation formula, the actual average deviation coefficient Z* of gas is related to the cumulative water production W p There is a relationship between the cumulative water production W p The first relationship model with the average coal reservoir pressure p, and when the given exhaust gas pressure is taken as the average coal reservoir pressure, the vertical axis prediction value p / Z* can be obtained according to the first relationship model and the sixth calculation formula.

[0121] In one embodiment of the present invention, step S800, determining a first relationship model between cumulative water production and average coal reservoir pressure, and determining a vertical axis prediction value of the prediction model at a given exhaust gas pressure based on the first relationship model, includes:

[0122] In step S810, the cumulative water production and average coal reservoir pressure corresponding to the last production date, as well as the iterative value of the control volume obtained in the last cyclic calculation, and the corrected values ​​of the reservoir porosity and water saturation are substituted into the tenth calculation formula to obtain the first relationship model, wherein the tenth calculation formula is:

[0123]

[0124] Where W p is the cumulative water production, (10 6 m 3 ); p is the average coal reservoir pressure, MPa; W psis the cumulative water production corresponding to the last production date, (10 6 m 3 );p s is the average coal reservoir pressure corresponding to the last production date, MPa; V is the iterative value of the control volume obtained in the last cycle calculation, (10 6 m 3 );φ ip The last corrected value of reservoir porosity obtained in the cycle calculation, decimal; S wip The last corrected value of water saturation obtained in the cycle calculation, decimal; R w is the water recovery factor, which is taken as 35%;

[0125] Step S820: determining a vertical axis prediction value of the prediction model under a given exhaust gas pressure according to the first relationship model.

[0126] In the first embodiment of the present invention, step S820, determining the vertical axis prediction value of the prediction model at a given exhaust gas pressure according to the first relationship model includes:

[0127] Substituting a given exhaust gas pressure as the average coal reservoir pressure into the first relationship model to calculate the cumulative water production under the given exhaust gas pressure;

[0128] Substituting the given exhaust gas pressure as the average coal reservoir pressure and the cumulative water production under the given exhaust gas pressure into the sixth calculation formula to obtain the actual average deviation coefficient of the gas under the given exhaust gas pressure;

[0129] The ratio of the given exhaust gas pressure to the actual average deviation coefficient of the gas at the given exhaust gas pressure is determined as the vertical axis prediction value of the prediction model at the given exhaust gas pressure.

[0130] It can be understood that in this embodiment, the vertical axis prediction value of the prediction model under a given exhaust gas pressure is obtained by formula calculation.

[0131] In the second embodiment of the present invention, step S820, determining the vertical axis prediction value of the prediction model at a given exhaust gas pressure according to the first relationship model includes:

[0132] Substituting a given pressure value lower than the average coal reservoir pressure corresponding to the last production date as the average coal reservoir pressure into the first relationship model to calculate the cumulative water production under the given pressure value;

[0133] Substituting the given pressure value and the cumulative water production at the given pressure value into the sixth calculation formula to obtain the actual average deviation coefficient of the gas at the given pressure value;

[0134] A second relationship model is established with a given pressure value as the average coal reservoir pressure as the horizontal axis and a ratio of the given pressure value to the actual average deviation coefficient of gas at the given pressure value as the vertical axis;

[0135] Substitute the given exhaust gas pressure as the average coal reservoir pressure into the second relationship model to obtain the vertical axis prediction value of the prediction model under the given exhaust gas pressure.

[0136] It can be understood that this embodiment first establishes a second relationship model between p / Z* and p through the first relationship model and the sixth calculation formula, and then uses the given exhaust gas pressure as the horizontal axis value to query the corresponding vertical axis value in the second relationship model, and determines it as the vertical axis prediction value of the prediction model under the given exhaust gas pressure.

[0137] Step S900: Substitute the predicted value on the vertical axis into the prediction model established last time in the cyclic calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate.

[0138] In one embodiment of the present invention, step S900, substituting the vertical axis prediction value into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate includes:

[0139] Substitute the predicted value on the vertical axis into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane. The eleventh calculation formula for the recoverable reserves of coalbed methane can be:

[0140]

[0141] Where G pab is the recoverable reserves of coalbed methane, (10 6 m 3 );p ab is the given exhaust gas pressure, MPa; Z ab * is the actual average deviation coefficient of the gas at a given exhaust pressure;

[0142] Substitute the recoverable reserves and the original gas reserves of the reservoir obtained in the last cycle calculation into the twelfth calculation formula to calculate the coalbed methane recovery rate, where the twelfth calculation formula is:

[0143]

[0144] Where R cbm is the recovery rate of coalbed methane; G pab is the recoverable reserves of coalbed methane, (10 6 m 3 );G i is the original gas reserves of the reservoir, (106m3).

[0145] The present invention is based on the material balance principle of deep coalbed methane reservoirs, takes into account the pressure difference between adsorbed gas pores and free gas pores, the change of coal reservoir physical parameters due to fracturing transformation, and the influence of dissolved gas, and proposes a method for predicting the ultimate recoverable reserves and recovery rate of deep coalbed methane. When the reservoir physical parameters, fluid physical parameters and fracturing fluid injection-flowback data are known, this method only requires measuring the average coal reservoir pressure and the corresponding cumulative gas production and water production data for at least two times to predict the ultimate recoverable reserves and recovery rate of deep coalbed methane. The method is concise and clear and is easy to promote and apply.

[0146] Example 1: A multi-stage fractured horizontal well P1 in a deep coalbed methane reservoir is drilled. The reservoir physical properties, fluid physical properties, and fracturing fluid injection-flowback data are known. During the production of the coalbed methane well, the average coal reservoir pressure is measured four times, and the coalbed methane recovery rate is predicted for given abandonment pressures of 4 MPa, 3 MPa, and 2 MPa, respectively.

[0147] 1. Organize and count the physical parameters of reservoirs and fluids

[0148] Table 1 Statistics of reservoir physical parameters and fluid physical parameters

[0149]

[0150]

[0151] 2. Organize and count the average coal reservoir pressure, cumulative gas production, cumulative water production under multiple production dates, and calculate the gas conventional average deviation coefficient

[0152] Table 2 Statistics of average coal reservoir pressure, cumulative production and gas conventional average deviation coefficient under multiple production dates

[0153]

[0154] 3. Calculate the capillary pressure between micropores and mesopores in coal reservoirs

[0155] The average pore size of the coal matrix micropores d = 2nm, the average pore size of the coal matrix mesopores D = 10nm, and the air-water interfacial tension σ gw =60mN / m and the coal matrix surface wetting angle θ = 89° are substituted into the first calculation formula to obtain the capillary pressure p between the micropores and mesopores of the coal reservoir. c =0.8377(MPa).

[0156]

[0157] The original coal reservoir pressure p i =21MPa and the capillary pressure between the micropores and mesopores of the coal reservoir p c=0.8377MPaSubstitute into the second calculation formula to calculate the original pressure p of the adsorbed gas in the adsorption pores of the coal reservoir mi =21.8377(MPa).

[0158] p mi =p i +p c =21+0.8377=21.8377 (MPa)

[0159] 4. Count the total fracturing fluid volume and cumulative flowback volume of deep coalbed methane wells, and calculate the net injection volume of fracturing

[0160] Statistics of the total fracturing fluid volume W during the fracturing process of deep coalbed methane wells fi =0.03(10 6 m 3 ) and the cumulative flowback volume W during the flowback process fp =0.0075(10 6 m 3 ), and use the third calculation formula to calculate the net injection volume W of fracturing fin =0.0225(10 6 m 3 ).

[0161] W fin =W fi -W fp =0.03-0.0075=0.0225(10 6 m 3 )

[0162] The results are recorded in Table 3.

[0163] Table 3 Statistics of fracturing and flowback data of deep coalbed methane wells

[0164] parameter Value unit <![CDATA[Total fracturing fluid volume W fi > 0.03 <![CDATA[10 6 m 3 ]]> <![CDATA[Cumulative return displacement W fp > 0.0075 <![CDATA[10 6 m 3 ]]> <![CDATA[Fracturing net injection volume W fin > 0.0225 <![CDATA[10 6 m 3 ]]>

[0165] 5. Calculate the corrected values ​​of reservoir porosity and water saturation after fracturing flowback and before production

[0166] First, according to geological knowledge, an initial given value is given for the control volume V of the coalbed methane well. The horizontal well section length of the coalbed methane well is 1000m, the horizontal well spacing is 350m, and the deep coal reservoir thickness is 10m. The initial given value of the control volume V of the deep coalbed methane well is calculated to be 3.5(10 6 m 3 ). The initial given value of V and the original porosity of the coal reservoir φ i =0.07, net injection volume of fracturing W fin =0.0225(10 6 m 3 ) and the volume coefficient of water Bw =1 is substituted into the fourth calculation formula to calculate the reservoir porosity φ after fracturing flowback and before production. ip The initial value of is 0.076429.

[0167]

[0168] The initial given value of the control volume V of the coalbed methane well is 3.5 (10 6 m 3 ), coal reservoir original porosity φ i =0.07, initial water saturation of coal reservoir S wi =0.60433, net injection volume of fracturing W fin =0.0225(10 6 m 3 ), the volume coefficient of water B w = 1 and the calculated reservoir porosity φ after fracturing flowback and before production ip = 0.076429 is substituted into the fifth calculation formula to calculate the water saturation S after fracturing flowback and before production. wip The initial value of is 0.63761.

[0169]

[0170] 6. Calculate the actual average deviation coefficient Z* and p / Z* of gas under multiple production dates

[0171] The sixth calculation formula is used to calculate Z* and p / Z* for multiple production dates and the results are recorded in Table 4.

[0172] Table 4 Reservoir production dynamic data statistics

[0173]

[0174] 7. Establish a prediction model for reservoir gas production and determine the original gas reserves of the reservoir

[0175] G p With p / Z* as the horizontal axis and p / Z* as the vertical axis, a scatter plot is drawn in the rectangular coordinate graph, such as Figure 2 As shown, using linear fitting, the slope value of the linear trend line obtained is -M=-0.442956 and the Y-axis intercept value is N=59.576835.

[0176] The seventh calculation formula is used to calculate the original gas reserves G of the reservoir. i The initial value is 134.49831(10 6 m 3 ).

[0177]

[0178] 8. Calculate the iterative value of the control volume and perform loop calculations

[0179] The iterative value of the control volume V calculated according to the eighth calculation formula is 3.5042742 (10 6 m 3 ).

[0180]

[0181] The iteration value of the control volume V is 3.5042742(10 6 m 3 ) replaces the initial given value of the control volume V to be 3.5(10 6 m 3 ), repeat steps 5 to 8 until the difference between the two consecutive calculated V values ​​is less than 10 -6 (10 6 m 3 ), stop the cycle, and finally determine the final value of the control volume V = 3.5042111 (10 6 m 3 ), reservoir porosity after fracturing flowback and before production φ ip The water saturation S after fracturing flowback and before production is 0.076421. wip =0.63757, the slope of the linear trend line is -M=-0.443006 and the Y-axis intercept is N=59.582443, and the original gas reserves of the reservoir controlled by the deep coalbed methane well P1 are calculated. i =134.49579(10 6 m 3 ).

[0182]

[0183] The final linear trend line expression obtained by the reservoir gas production prediction model is:

[0184]

[0185] Compare p / Z* with G p The linear fitting trend line in the rectangular coordinate graph is extended to the intersection with the horizontal axis. The value corresponding to the intersection is the original gas reserves G of the reservoir controlled by the deep coalbed methane well. i ,like Figure 3 shown.

[0186] 9. Determine W p and the first relationship model between p, and the second relationship model between p / Z* and p

[0187] It can be seen from Table 2 that the average coal reservoir pressure p in the deep coalbed methane well wass The cumulative water production under the last measured average coal reservoir pressure of deep coalbed methane wells is 9.5 (MPa), W ps is 0.014221(10 6 m 3 ).

[0188] The final value of the control volume V of the CBM well P1 will be determined as 3.5042111, and the reservoir porosity φ after fracturing flowback and before production ip The value of 0.076421, the water saturation S after fracturing flowback and before production wip The value of 0.63757, the water recovery rate R w The value of 35%, the average coal reservoir pressure p of the deep coalbed methane well last measured s The value of 9.5, the cumulative water production of deep coalbed methane wells under the last measured average coal reservoir pressure W ps Substitute the value 0.014221 into the tenth calculation formula to obtain W p The relationship between and p is:

[0189]

[0190] Given any pressure p lower than the last measured average coal reservoir pressure, use the tenth calculation formula to calculate W p ,like Figure 4 As shown, the cumulative water production W is obtained p The first relationship model is the average coal reservoir pressure p. Then the pressure p and the calculated W p Substitute into the sixth calculation formula to calculate Z* at the pressure p, and then calculate p / Z* at the pressure p.

[0191] Taking pressure p=7MPa as an example, use the tenth calculation formula to calculate W p is 0.03699(10 6 m 3 ).

[0192]

[0193] Then the pressure p=7MPa, W p =0.03699(10 6 m 3 ) is substituted into the sixth calculation formula, and Z* is calculated to be 0.156526 at a pressure of p = 7 MPa, and then p / Z* is calculated to be 44.72088 at a pressure of p = 7 MPa.

[0194] With p as the horizontal axis and p / Z* as the vertical axis, draw the second relationship model between p / Z* and p in the rectangular coordinate diagram, such as Figure 5shown.

[0195] 10. Predict the given waste pressure p ab The recovery rate of coalbed methane under

[0196] When in p ab When the pressures are 4MPa, 3MPa and 2MPa respectively, according to the second relationship model between p / Z* and p predicted by deep coalbed methane well P1, we can find p ab The p corresponding to 4MPa, 3MPa and 2MPa ab / Z ab * are 36.996426 (MPa), 33.201957 (MPa) and 28.317827 (MPa), respectively. Figure 6 shown.

[0197] Or discard the pressure p ab =4MPa, 3MPa and 2MPa are substituted into the tenth calculation formula respectively to calculate W pab They are 0.045528(10 6 m 3 )、0.047109(10 6 m 3 ) and 0.048374(10 6 m 3 ); ab =4MPa, 3MPa and 2MPa and W pab =0.045528(10 6 m 3 )、0.047109(10 6 m 3 ) and 0.048374(10 6 m 3 ) are substituted into the sixth calculation formula to calculate p ab = Z at 4MPa, 3MPa and 2MPa ab * are 0.108119, 0.090356 and 0.070627 respectively, and then p is calculated ab = p at 4MPa, 3MPa and 2MPa ab / Z ab *36.996426 (MPa), 33.201957 (MPa) and 28.317827 (MPa) respectively.

[0198] In p / Z* and G p Find p on the extension line of the linear fitting trend line of the forecast model ab / Z ab*=36.996426(MPa), 33.201957(MPa) and 28.317827(MPa), corresponding to G p They are 50.983547(10 6 m 3 )、59.548823(10 6 m 3 ) and 70.573798(10 6 m 3 ), that is, the waste pressure p ab = Final recoverable reserves of coalbed methane corresponding to 4MPa, 3MPa and 2MPa G pab They are 50.983547(10 6 m 3 )、59.548823(10 6 m 3 ) and 70.573798(10 6 m 3 ),like Figure 7 shown.

[0199] Or put p ab / Z ab *Substitute into the eleventh calculation formula to calculate the waste pressure p ab The corresponding ultimate recoverable reserves of coalbed methane G pab .

[0200] With the discard pressure p ab =3MPa as an example, take p ab / Z ab *=33.201957(MPa)Substitute into the eleventh calculation formula to calculate the waste pressure p ab = The ultimate recoverable reserves of coalbed methane corresponding to 3MPa G pab is 59.548823(10 6 m 3 ).

[0201]

[0202] Use the twelfth calculation formula to calculate the waste pressure p ab =4MPa, 3MPa and 2MPa corresponding coalbed methane recovery rates are 37.91%, 44.28% and 52.47% respectively.

[0203] With the discard pressure p ab =3MPa as an example, the waste pressure p ab =The ultimate recoverable reserves of coalbed methane corresponding to 3MPa G pab =59.548823(10 6 m3 ) and the original gas reserves G controlled by deep coalbed methane well P1 i =134.49579(10 6 m 3 ) is substituted into the twelfth calculation formula to calculate the waste pressure p ab =3MPa corresponds to a coalbed methane recovery rate of 44.28%.

[0204]

[0205] In addition, another embodiment of the present invention provides a processor configured to execute the deep coalbed methane recovery rate prediction method described above.

[0206] In addition, another embodiment of the present invention provides a machine-readable storage medium, on which instructions are stored. When the instructions are executed by a processor, the deep coalbed methane recovery rate prediction method described above is implemented.

[0207] Those skilled in the art will appreciate that the embodiments of the present application can be provided as methods, systems, or computer program products. Therefore, the present application can 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 can adopt the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to magnetic disk storage, CD-ROM, optical storage, etc.) that contain computer-usable program code.

[0208] 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 produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the steps in the process. 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.

[0209] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work 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 The function specified in one or more boxes.

[0210] 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 the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 The steps for the function specified in one or more boxes.

[0211] In a typical configuration, a computing device includes one or more processors (CPUs), input / output interfaces, network interfaces, and memory.

[0212] 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.

[0213] It should also be noted that the terms "comprises," "includes," or any other variations thereof are intended to encompass non-exclusive inclusion, such that a process, method, commodity, or apparatus that includes a series of elements includes not only those elements but also other elements not explicitly listed, or includes elements inherent to such process, method, commodity, or apparatus. In the absence of further limitations, an element defined by the phrase "comprises a ..." does not exclude the presence of other identical elements in the process, method, commodity, or apparatus that includes the element.

[0214] The above are merely 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 modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present application should all be included within the scope of the claims of the present application.

Claims

1. A method for predicting deep coalbed methane recovery rate, characterized in that: The deep coalbed methane recovery rate prediction method includes: Determine the physical properties of the reservoir and fluid respectively; Determine the average coal reservoir pressure, cumulative gas production and cumulative water production under multiple production dates, and determine the gas conventional average deviation coefficient based on the average coal reservoir pressure; Determine the capillary pressure between the micropores and mesopores of the reservoir; According to the initial given value of the control volume, the correction values ​​of the reservoir porosity and water saturation after fracturing flowback and before production are determined respectively; Calculate the actual average deviation coefficient of gas based on the physical properties, capillary pressure, initial given values ​​of control volume, corrected values ​​of reservoir porosity and water saturation, average coal reservoir pressure under multiple production dates, cumulative water production, and conventional average deviation coefficient of gas; A prediction model for reservoir gas production is established with the cumulative gas production as the horizontal axis and the ratio of the average coal reservoir pressure to the actual average deviation coefficient of gas as the vertical axis, and the original gas reserves of the reservoir are determined based on the prediction model for reservoir gas production. An iterative value of the control volume is calculated based on the corrected values ​​of the physical parameters, capillary pressure, reservoir porosity and water saturation, and the original gas reserves of the reservoir, and the iterative value is returned to replace the initial given value of the control volume for cyclic calculation until the difference between the iterative values ​​of the control volume calculated two consecutive times is less than a preset value, and the cycle stops; Determining a first relationship model between cumulative water production and average coal reservoir pressure, and determining a vertical axis prediction value of a prediction model under a given exhaust gas pressure based on the first relationship model; Substitute the predicted value on the vertical axis into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate; The calculation of the actual average deviation coefficient of gas based on the physical parameters, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, and average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas under multiple production dates includes: Substitute the physical properties, capillary pressure, initial given values ​​of the control volume, corrected values ​​of reservoir porosity and water saturation, average coal reservoir pressure, cumulative water production, and conventional average deviation coefficient of gas into the sixth calculation formula to calculate the actual average deviation coefficient of gas under multiple production dates. The sixth calculation formula is: Where, Z* is the actual average deviation coefficient of the gas, dimensionless; ρ c is the coal rock density, t / m 3 ; V L is the Langmuir volume, m 3 / t; p L is the Langmuir pressure, MPa; p c is the capillary pressure between micropores and mesopores in the reservoir, MPa; φ ip is the corrected value of reservoir porosity, decimal; S wip is the corrected value of water saturation, decimal; Z sc is the natural gas deviation coefficient under standard conditions, dimensionless, and its value is 1; T sc is the temperature under standard conditions, K, and its value is 293.15; p i is the original coal reservoir pressure, MPa; p sc is the pressure under standard conditions, MPa, and its value is 0.101325; T is the coal reservoir temperature, K; p is the average coal reservoir pressure, MPa; Z is the conventional average deviation coefficient of gas, dimensionless; C p is the pore compression coefficient, MPa -1 ; C w is the isothermal compressibility of water, MPa -1 ; C s is the solubility coefficient of coalbed methane in water, MPa -1 ; C a is the coal matrix shrinkage coefficient, dimensionless; W e is the cumulative water intrusion, (10 6 m 3 ), take 0; W p is the cumulative water production, (10 6 m 3 ); B w is the volume coefficient of water, m 3 / m 3 , the value is 1; V is the initial given value of the control volume, (10 6 m 3 )； Determining a first relationship model between the cumulative water production and the average coal reservoir pressure, and determining a vertical axis prediction value of the prediction model under a given exhaust gas pressure based on the first relationship model includes: Substitute the cumulative water production and average coal reservoir pressure corresponding to the last production date, the iterative value of the control volume obtained in the last cycle calculation, and the corrected values ​​of the reservoir porosity and water saturation into the tenth calculation formula to obtain the first relationship model, where the tenth calculation formula is: ； Where, W p is the cumulative water production, (10 6 m 3 ); p is the average coal reservoir pressure, MPa; W ps is the cumulative water production corresponding to the last production date, (10 6 m 3 ); p s is the average coal reservoir pressure corresponding to the last production date, MPa; V is the iterative value of the control volume obtained in the last cyclic calculation, (10 6 m 3 ); φ ip It is the corrected value of reservoir porosity obtained last time in the cycle calculation, decimal; S wip It is the corrected value of water saturation obtained last time in the cycle calculation, decimal; R w is the water recovery factor, which is taken as 35%; The vertical axis prediction value of the prediction model at a given exhaust gas pressure is determined according to the first relationship model.

2. The deep coalbed methane recovery rate prediction method according to claim 1, characterized in that: Determining the vertical axis prediction value of the prediction model at a given exhaust gas pressure according to the first relationship model includes: Substituting a given exhaust gas pressure as the average coal reservoir pressure into the first relationship model to calculate the cumulative water production under the given exhaust gas pressure; Substituting the given exhaust gas pressure as the average coal reservoir pressure and the cumulative water production under the given exhaust gas pressure into the sixth calculation formula to obtain the actual average deviation coefficient of the gas under the given exhaust gas pressure; The ratio of the given exhaust gas pressure to the actual average deviation coefficient of the gas at the given exhaust gas pressure is determined as the vertical axis prediction value of the prediction model at the given exhaust gas pressure.

3. The method for predicting deep coalbed methane recovery rate according to claim 1, characterized in that: Determining the vertical axis prediction value of the prediction model at a given exhaust gas pressure according to the first relationship model includes: Substituting a given pressure value lower than the average coal reservoir pressure corresponding to the last production date as the average coal reservoir pressure into the first relationship model to calculate the cumulative water production under the given pressure value; Substituting the given pressure value and the cumulative water production at the given pressure value into the sixth calculation formula to obtain the actual average deviation coefficient of the gas at the given pressure value; A second relationship model is established with a given pressure value as the average coal reservoir pressure as the horizontal axis and a ratio of the given pressure value to the actual average deviation coefficient of gas at the given pressure value as the vertical axis; Substitute the given exhaust gas pressure as the average coal reservoir pressure into the second relationship model to obtain the vertical axis prediction value of the prediction model under the given exhaust gas pressure.

4. The method for predicting deep coalbed methane recovery rate according to any one of claims 1 to 3, characterized in that: Determining the capillary pressure between the micropores and mesopores of the reservoir comprises: The capillary pressure between the micropores and mesopores of the reservoir is determined according to the first calculation formula, wherein the first calculation formula is: ； Where, p c is the capillary pressure between micropores and mesopores in the reservoir, MPa; d is the average pore size of the coal matrix micropores, nm; D is the average pore size of coal matrix mesopores, nm; σ gw is the air-water interfacial tension, mN / m; θ is the wetting angle of the coal matrix surface, °.

5. The method for predicting deep coalbed methane recovery rate according to any one of claims 1 to 3, characterized in that: The method of determining the corrected values ​​of the reservoir porosity and water saturation after fracturing flowback and before production based on the initial given value of the control volume includes: Substitute the initial given value of the control volume into the fourth and fifth calculation formulas respectively to calculate the corrected value of the reservoir porosity and the corrected value of the water saturation after fracturing flowback and before production. The fourth calculation formula is: ； Where, φ ip is the corrected value of reservoir porosity, decimal; φ i is the original porosity of the coal reservoir, decimal; W fin is the net injection volume of fracturing, (10 6 m 3 ); B w is the volume coefficient of water, m 3 / m 3 , the value is 1; V is the initial given value of the control volume, (10 6 m 3 ); The fifth calculation formula is: ； Where, S wip is the corrected value of water saturation, decimal; φ i is the original porosity of the coal reservoir, decimal; W fin is the net injection volume of fracturing, (10 6 m 3 ); B w is the volume coefficient of water, m 3 / m 3 , the value is 1; φ ip is the corrected value of reservoir porosity, decimal.

6. The method for predicting deep coalbed methane recovery rate according to any one of claims 1 to 3, characterized in that: The method further includes determining the corrected values ​​of the reservoir porosity and water saturation after fracturing flowback and before production based on the initial given value of the control volume: Substitute the total fracturing fluid volume during the fracturing process and the cumulative flowback volume during the flowback process into the third calculation formula to calculate the net fracturing injection volume, where the third calculation formula is: ； Where, W fin is the net injection volume of fracturing, (10 6 m 3 ); W fi is the total amount of fracturing fluid during the fracturing process, (10 6 m 3 ); W fp is the cumulative flowback volume during the flowback process, (10 6 m 3 ).

7. The method for predicting deep coalbed methane recovery rate according to any one of claims 1 to 3, characterized in that: The step of calculating an iterative value of the control volume according to the physical parameters, capillary pressure, the corrected values ​​of the reservoir porosity and water saturation, and the original gas reserves of the reservoir, and returning the iterative value to replace the initial given value of the control volume for cyclic calculation until the difference between the iterative values ​​of the control volume calculated two consecutive times is less than a preset value and the cycle is stopped includes: Substitute the corrected values ​​of the physical properties, capillary pressure, reservoir porosity and water saturation, and the original gas reserves of the reservoir into the eighth calculation formula to calculate the iterative value of the control volume, where the eighth calculation formula is: ； Where, V is the iteration value of the control volume, (10 6 m 3 ); G i is the original gas reserves of the reservoir, (10 6 m 3 ); ρ c is the coal rock density, t / m 3 ; V L is the Langmuir volume, m 3 / t; p L is the Langmuir pressure, MPa; p c is the capillary pressure between micropores and mesopores in the reservoir, MPa; φ ip is the corrected value of reservoir porosity, decimal; S wip is the corrected value of water saturation, decimal; Z sc is the natural gas deviation coefficient under standard conditions, dimensionless, and its value is 1; T sc is the temperature under standard conditions, K, and its value is 293.15; p sc is the pressure under standard conditions, MPa, and its value is 0.101325; p i is the original coal reservoir pressure, MPa; T is the coal reservoir temperature, K; Z i is the deviation coefficient of gas at the original coal reservoir pressure, dimensionless; C s is the solubility coefficient of coalbed methane in water, MPa -1 ; The iteration value is returned to replace the initial given value of the control volume for cyclic calculation until the difference between the iteration values ​​of the control volume calculated twice is less than the preset value and the cycle is stopped.

8. The method for predicting deep coalbed methane recovery rate according to any one of claims 1 to 3, characterized in that: Substituting the vertical axis prediction value into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate includes: Substitute the predicted value on the vertical axis into the prediction model established last time in the cycle calculation to obtain the recoverable reserves of coalbed methane; Substitute the recoverable reserves and the original gas reserves of the reservoir obtained in the last cycle calculation into the twelfth calculation formula to calculate the coalbed methane recovery rate, where the twelfth calculation formula is: ； Where, R cbm is the coalbed methane recovery rate; G pab is the recoverable reserves of coalbed methane, (10 6 m 3 ); G i is the original gas reserves of the reservoir, (10 6 m 3 ).

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