CN-121993190-A - Coalbed methane original geological reserve evaluation method considering fracturing fluid injection flowback

CN121993190ACN 121993190 ACN121993190 ACN 121993190ACN-121993190-A

Abstract

The invention discloses a coalbed methane original geological reserve evaluation method considering fracturing fluid injection flowback, which comprises the steps of calculating a apparent pressure correction coefficient according to reservoir physical parameters, fluid physical parameters, average coal reservoir pressure and average gas deviation coefficient under a plurality of production dates, correcting the apparent pressure of the average coal reservoir according to the apparent pressure correction coefficient to obtain corrected apparent average coal reservoir pressure, determining equivalent accumulated gas yield according to the reservoir physical parameters, the fluid physical parameters, injection and return displacement of fracturing fluid and the average coal reservoir pressure, accumulated gas yield, accumulated water yield and average gas deviation coefficient under the plurality of production dates, establishing a prediction fitting model according to the equivalent accumulated gas yield and corrected apparent average coal reservoir pressure based on a substance balance principle, determining the original geological reserve of the coalbed methane, avoiding cyclic iteration, considering the influences of fracturing fluid injection and return discharge, improving calculation efficiency, and being convenient for large-scale popularization and application.

Inventors

SHI JUNTAI
HUANG HAI
CHEN MING
HUANG HONGXING
LIU YAN
SUN ZHENG
Ji changjiang
ZHANG WENTONG

Assignees

西安石油大学

Dates

Publication Date: 20260508
Application Date: 20260114

Claims (9)

1. A method for evaluating original geological reserves of coal bed gas by considering fracturing fluid injection flowback, which is characterized by comprising the following steps: respectively determining reservoir physical parameters, fluid physical parameters and injection quantity and return displacement of fracturing fluid; Determining average coal reservoir pressure, accumulated gas yield and accumulated water yield on a plurality of production dates, and determining an average gas deviation coefficient according to the average coal reservoir pressure; Calculating a apparent pressure correction coefficient according to reservoir physical parameters, fluid physical parameters, average coal reservoir pressure and average gas deviation coefficients under a plurality of production dates, and correcting the apparent average coal reservoir pressure under the plurality of production dates according to the apparent pressure correction coefficient to obtain corrected apparent average coal reservoir pressure; determining equivalent accumulated gas yield according to reservoir physical parameters, fluid physical parameters, injection amount and return displacement of fracturing fluid, average coal reservoir pressure, accumulated gas yield, accumulated water yield and average gas deviation coefficient under a plurality of production dates; And establishing a predictive fit model based on a substance balance principle according to the equivalent accumulated gas yield and the corrected apparent average coal reservoir pressure, and determining the original geological reserve of the coal bed gas according to the predictive fit model.
2. The method for evaluating the original geological reserves of the coalbed methane taking into account the fracturing fluid injection flowback according to claim 1, wherein the calculating the apparent pressure correction coefficient according to the reservoir physical property parameter, the fluid physical property parameter, the average coal reservoir pressure at a plurality of production dates and the average gas deviation coefficient, and correcting the apparent average coal reservoir pressure at a plurality of production dates according to the apparent pressure correction coefficient to obtain the corrected apparent average coal reservoir pressure comprises: Substituting reservoir physical property parameters, fluid physical property parameters, average coal reservoir pressure and average gas deviation coefficients under a plurality of production dates into a calculation formula of a apparent pressure correction coefficient to calculate the apparent pressure correction coefficient under the plurality of production dates respectively, wherein the calculation formula of the apparent pressure correction coefficient is as follows: Wherein α is a apparent pressure correction coefficient, dimensionless, p sc is a pressure under a standard condition, MPa is taken as 0.101325, T is a coal reservoir temperature, K, ρ ad is a coal rock air drying matrix volume density, t/m 3 ;V L is a coal air drying matrix Langmuir volume, m 3 /t, Z is an average gas deviation coefficient under an average coal reservoir pressure, dimensionless, φ i is a coal reservoir original porosity, decimal, Z sc is a natural gas deviation coefficient under a standard condition, dimensionless is taken as 1;T sc is a temperature under a standard condition, K is taken as 293.15, p L is a coal air drying matrix Langmuir pressure, MPa is taken as an average coal reservoir pressure, S wi is an original water saturation, decimal, C p is a coal reservoir pore compression coefficient, MPa -1 ;C w is an isothermal compression coefficient of water, MPa -1 ;p i is an original reservoir pressure, MPa, C a is a matrix shrinkage coefficient, C s is a water-free coal layer, and a water-soluble in a coal reservoir pressure, and a dimensionless coal layer is taken as a water deviation coefficient; And correcting the apparent average coal reservoir pressure at a plurality of production dates according to the apparent pressure correction coefficient to obtain corrected apparent average coal reservoir pressure.
3. The method of evaluating a raw geological reserve of coalbed methane with consideration of fracturing fluid injection flowback of claim 2, wherein said correcting the apparent average coal reservoir pressure at a plurality of production dates according to the apparent pressure correction factor to obtain a corrected apparent average coal reservoir pressure comprises: Substituting the apparent pressure correction coefficient, the average coal reservoir pressure and the average gas deviation coefficient under the same production date into a correction calculation formula of the apparent average coal reservoir pressure to obtain corrected apparent average coal reservoir pressure, wherein the correction calculation formula of the apparent average coal reservoir pressure is as follows: p α =α·p/Z Wherein p α is the corrected apparent average coal reservoir pressure, MPa, alpha is the apparent pressure correction coefficient, and dimensionless, p is the average coal reservoir pressure, MPa, and Z is the average gas deviation coefficient under the average coal reservoir pressure.
4. The method for evaluating the original geological reserves of the coalbed methane taking into account the injection flowback of the fracturing fluid according to claim 1, wherein the determining the equivalent accumulated gas yield according to the reservoir physical parameters, the fluid physical parameters, the injection amount and the flowback amount of the fracturing fluid and the average coal reservoir pressure, the accumulated gas yield, the accumulated water yield and the average gas deviation coefficient under a plurality of production dates comprises: Substituting reservoir physical parameters, fluid physical parameters, injection amount and return displacement of fracturing fluid and average coal reservoir pressure, accumulated gas yield, accumulated water yield and average gas deviation coefficient under a plurality of production dates into a calculation formula of equivalent accumulated gas yield to calculate equivalent accumulated gas yield under a plurality of production dates respectively, wherein the calculation formula of equivalent accumulated gas yield is as follows: Wherein G peq is equivalent accumulated gas yield, 10 8 m 3 ;G p is accumulated gas yield, 10 8 m 3 ;W p1 is return displacement of fracturing fluid, 10 8 m 3 ;W p2 is accumulated water yield, 10 8 m 3 ;W in is injection amount of fracturing fluid, 10 8 m 3 ;B w is volume coefficient of water, m 3 /m 3 is 1, Z sc is natural gas deviation coefficient under standard condition, dimensionless is 1;T sc is temperature under standard condition, K is 293.15, p is average coal reservoir pressure, MPa, Z is average gas deviation coefficient under average coal reservoir pressure, dimensionless is T is coal reservoir temperature, K, p sc is pressure under standard condition, MPa is 0.101325, C s is dissolution coefficient of coal bed gas in water, and MPa -1 .
5. The method for evaluating the original geological reserves of the coalbed methane taking into account the fracturing fluid injection flowback according to any one of claims 1 to 4, wherein the establishing a predictive fit model based on a substance balance principle according to the equivalent accumulated gas yield and the corrected apparent average coal reservoir pressure, and determining the original geological reserves of the coalbed methane according to the predictive fit model comprises: establishing a prediction fitting model based on a material balance principle, wherein the prediction fitting model is set to be a linear fitting model taking equivalent accumulated gas yield as a horizontal axis and corrected apparent average coal reservoir pressure as a vertical axis; and determining the original geological reserve of the coal bed gas according to the predictive fit model.
6. The method for evaluating the original geological reserves of the coalbed methane taking into account the fracturing fluid injection flowback according to claim 5, wherein the establishing a predictive fit model based on the mass balance principle, wherein the predictive fit model is set as a linear fit model taking the equivalent accumulated gas yield as a horizontal axis and the corrected apparent average coal reservoir pressure as a vertical axis comprises: Establishing a material balance equation of the coal bed gas by considering fracturing fluid injection and flowback, wherein the material balance equation is as follows: Wherein, alpha.p/Z is the corrected apparent average coal reservoir pressure, MPa, p i is the original coal reservoir pressure, MPa, Z i is the gas deviation coefficient under the original coal reservoir pressure, and G is the original geological reserve of the coalbed methane, 10 8 m 3 ;G peq is the equivalent accumulated gas yield, 10 8 m 3 ; And drawing a scatter diagram in a rectangular coordinate system by taking the equivalent accumulated gas yield as a horizontal axis and the corrected apparent average coal reservoir pressure as a vertical axis, and performing linear fitting on the scatter diagram to obtain a prediction fitting model.
7. The method for evaluating the original geological reserves of the coalbed methane by considering the fracturing fluid injection flowback according to claim 5, wherein the calculation formula of the predictive fit model is as follows: Wherein alpha.p/Z is the corrected apparent average coal reservoir pressure, MPa, G peq is the equivalent accumulated gas yield, 10 8 m 3 , M is the negative slope value of the predictive fit model, and N is the vertical axis intercept value of the predictive fit model, and 。
8. The method of evaluating an original geological reserve of coalbed methane with consideration of fracturing fluid injection flowback of claim 5, wherein said determining an original geological reserve of coalbed methane based on a predictive fit model comprises: And calculating according to the slope value and the vertical axis intercept value of the predictive fit model to obtain the original geological reserve of the coal bed methane, wherein the calculation formula of the original geological reserve is as follows: Wherein G is the original geological reserve of the coal bed gas, 10 8 m 3 , M is the negative slope value of the predictive fit model, and N is the vertical axis intercept value of the predictive fit model.
9. The method for evaluating the original geological reserves of coal-bed methane taking into account fracturing fluid injection flowbacks according to any one of claims 1 to 4, wherein said determining the average gas deviation coefficient from the average coal-bed methane pressure comprises: the Dranchuk-Abou-Kassem method was used to obtain an average gas bias factor based on the relative density of the coalbed methane, the temperature of the coal reservoir, and the average pressure of the coal reservoir over a number of production dates.

Description

Coalbed methane original geological reserve evaluation method considering fracturing fluid injection flowback Technical Field The invention belongs to the technical field of coalbed methane exploitation, and particularly relates to a coalbed methane original geological reserve evaluation method considering fracturing fluid injection flowback. Background Coalbed methane is commonly called as "gas", and is associated with coal, and is an unconventional natural gas stored in the coal layer in an adsorption state. The original geological reserve of the coal bed gas determines the development scale and the development mode of the coal bed gas, so that the accurate evaluation of the original geological reserve of the coal bed gas has very important theoretical and practical significance for the efficient development of the coal bed gas. Currently, methods for evaluating the original geological reserves of coalbed methane include both static methods and dynamic methods. The static method is based on the principle of a volumetric method, the calculation result is reliable under the condition that the well control area is known, but the well control area is generally difficult to acquire in advance, and adjustment is brought to calculation of reserves of the volumetric method. In the dynamic method, the material balance method is usually based on the quasi-average gas deviation coefficient Z of the coalbed methane, and in the process of calculating the quasi-average gas deviation coefficient Z, the control volume V of the coal-bed gas well needs to be circularly determined, so that the calculation complexity is increased, and the influence of fracturing fluid injection and flowback is mostly ignored in the existing method for evaluating the original geological reserves of the coal-bed gas, so that the reliability of evaluation is influenced. Disclosure of Invention Aiming at the defects or shortcomings in the prior art, the invention provides a coalbed methane original geological reserve evaluation method considering fracturing fluid injection flowback, and aims to solve the technical problems that the existing coalbed methane original geological reserve evaluation method is complex in calculation and influences of fracturing fluid injection and flowback are ignored. In order to achieve the above object, the present invention provides a method for evaluating an original geological reserve of coalbed methane in consideration of a fracturing fluid injection flowback, wherein the method for evaluating an original geological reserve of coalbed methane in consideration of a fracturing fluid injection flowback comprises: respectively determining reservoir physical parameters, fluid physical parameters and injection quantity and return displacement of fracturing fluid; Determining average coal reservoir pressure, accumulated gas yield and accumulated water yield on a plurality of production dates, and determining an average gas deviation coefficient according to the average coal reservoir pressure; Calculating a apparent pressure correction coefficient according to reservoir physical parameters, fluid physical parameters, average coal reservoir pressure and average gas deviation coefficients under a plurality of production dates, and correcting the apparent average coal reservoir pressure under the plurality of production dates according to the apparent pressure correction coefficient to obtain corrected apparent average coal reservoir pressure; determining equivalent accumulated gas yield according to reservoir physical parameters, fluid physical parameters, injection amount and return displacement of fracturing fluid, average coal reservoir pressure, accumulated gas yield, accumulated water yield and average gas deviation coefficient under a plurality of production dates; And establishing a predictive fit model based on a substance balance principle according to the equivalent accumulated gas yield and the corrected apparent average coal reservoir pressure, and determining the original geological reserve of the coal bed gas according to the predictive fit model. In one embodiment of the present invention, calculating a apparent pressure correction factor based on reservoir physical properties parameters, fluid physical properties parameters, average coal reservoir pressure at a plurality of production dates, and average gas deviation factor, and correcting the apparent average coal reservoir pressure at the plurality of production dates based on the apparent pressure correction factor to obtain a corrected apparent average coal reservoir pressure comprises: Substituting reservoir physical property parameters, fluid physical property parameters, average coal reservoir pressure and average gas deviation coefficients under a plurality of production dates into a calculation formula of a apparent pressure correction coefficient to calculate the apparent pressure correction coefficient under the plurality of production dates r