A shale gas reserve evaluation method

Abstract

The present invention discloses a shale gas reserve evaluation method, which belongs to the field of oil and gas geological technology and is characterized by comprising the following steps: a. obtaining formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, natural gas molar mass M, g , natural gas critical pressure P cr , natural gas critical temperature T cr , natural gas density ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity; b. Obtain the shale reservoir distribution area A, shale reservoir thickness H, shale reservoir porosity φ, and irreducible water saturation SW i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the adsorbed gas reserve calculation model; c. obtain the shale reservoir distribution area A, shale reservoir thickness H, and natural gas volume coefficient B g , determine the free gas reserve calculation model; d, determine the shale gas reserve calculation model. The present invention greatly improves the accuracy of shale gas reserve evaluation.

Description

Technical Field

[0001] The present invention relates to the field of oil and gas geology technology, and in particular to a shale gas reserve evaluation method. Background Art

[0002] Shale gas is natural gas, primarily hydrocarbon gas, occurring in free and adsorbed states within organic-rich shale formations. Shale gas reserves are defined as the amount of natural gas present in organic-rich shale formations. The oil and gas reserve calculation standards include three reserve evaluation methods: volumetric, dynamic, and probabilistic. Conventional natural gas reservoirs primarily consist of free gas, and large-scale reserve evaluation often uses the volumetric method. Shale gas, on the other hand, is an unconventional natural gas reservoir, containing both free and adsorbed gas, and the underground densities of free and adsorbed gas differ.

[0003] Currently, shale gas reserve calculations evaluate free gas and adsorbed gas at the same density, resulting in underestimated shale gas reserves. In early shale gas reserve evaluations, adsorbed gas did not occupy pore space, resulting in underestimated shale gas reserves. Furthermore, isothermal adsorption experimental data are often used in adsorbed gas evaluation. These experiments were conducted with dry shale, without considering bound water, which generally occupies the pore space with adsorbed gas. Consequently, the experimental data represent the maximum possible amount of adsorbed gas, resulting in underestimated adsorbed gas reserves.

[0004] A Chinese patent document with publication number CN108303510A, published on July 20, 2018, discloses a method for evaluating shale gas reservoir performance, which is characterized by comprising:

[0005] Calculating a first characterization parameter of a target shale gas reservoir based on multiple geological parameters of the target shale gas reservoir; wherein the multiple geological parameters are used to represent the physical and chemical properties of the target shale gas reservoir; the geological parameters of the target shale gas reservoir are obtained based on well logging interpretation; and the first characterization parameter is used to characterize the reserves of the target shale gas reservoir;

[0006] Calculating a second characterization parameter of the target shale gas reservoir based on the well logging data and the geological parameters; wherein the second characterization parameter is used to represent the degree of deformation of the target shale gas reservoir after fracturing;

[0007] The performance of the shale gas reservoir is obtained according to the first characterization parameter and the second characterization parameter in accordance with a specified evaluation rule; wherein the evaluation rule is used to represent the range interval of the first characterization parameter and the second characterization parameter corresponding to shale gas reservoirs with different reservoir performance.

[0008] While the shale gas reservoir performance evaluation method disclosed in this patent document achieves a simple and efficient evaluation of reservoir gas storage performance, it does not deduct the pore space occupied by adsorbed gas from the porosity used to calculate free gas, resulting in an overestimation of the free gas content and affecting the accuracy of reserve calculations. Summary of the Invention

[0009] To overcome the above-mentioned deficiencies of the prior art, the present invention provides a shale gas reserve evaluation method. The present invention first evaluates the maximum possible adsorbed gas volume of shale gas, then assesses the maximum possible pore space occupied by the adsorbed gas based on the adsorbed gas density, deducts the pore space occupied by bound water, and then evaluates the adsorbed gas reserves to obtain a relatively accurate adsorbed gas reserve. Then, after deducting the pore space occupied by the adsorbed gas and bound water, the free gas reserves are evaluated using a volumetric method to obtain a relatively accurate free gas reserve. Finally, an overall shale gas reserve evaluation is performed, thereby greatly improving the accuracy of shale gas reserve evaluation.

[0010] The present invention is achieved through the following technical solutions:

[0011] A shale gas reserve evaluation method, characterized by comprising the following steps:

[0012] a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity;

[0013] b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves;

[0014] c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model;

[0015] d. Determine the shale gas reserve calculation model.

[0016] In step a, the ground standard temperature and pressure refers to a temperature of 20° C. and a pressure of 0.1 MPa.

[0017] In step a, the maximum adsorption volume per unit is determined based on the formation temperature T and the formation pressure P in the dry core shale isothermal adsorption curve. max .

[0018] In the step a, determining the adsorbed gas density calculation model refers to determining it by formula 1;

[0019] ρ gd =8M g P cr / RT cr Formula 1

[0020] Where: ρ gd is the adsorption density, t / m 3 ;M g is the gas molar mass, g / mol; P cr is the critical pressure of natural gas, MPa; R is the gas constant, which is 8.314 J / (mol.K); T cr is the critical temperature of natural gas, K.

[0021] In the step a, determining the calculation model of the adsorbed gas and water porosity refers to determining it by formula 2;

[0022] φ ga =ΔV max ρ gs ρ c / ρ gd

[0023] If φ ga >φ, then φ ga =φ

[0024] If φ ga <SW i φ, then φ ga =SW i φ Equation 2

[0025] Where: φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; ΔV max is the maximum adsorption volume per unit, m 3 / t;ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 ρ c is the shale density, m 3 / t;ρ gd is the density of adsorbed gas in the formation, t / m 3 ; SW i is the bound water saturation.

[0026] In the step b, determining the adsorbed gas reserve calculation model refers to determining it by formula 3;

[0027] G ga =0.01AHρ gd (φga -SW i φ) / ρ gs Formula 3

[0028] Where: G ga is the adsorbed gas reserve, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; ρ gd is the density of adsorbed gas in the formation, t / m 3 ;φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; SW i is the bound water saturation; ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 .

[0029] In step c, the free gas reserves refer to the free gas reserves stored in the pores of the shale reservoir, converted to the amount of natural gas at a temperature of 20° C. and a pressure of 0.1 MPa.

[0030] In the step c, determining the free gas reserve calculation model refers to determining it by using formula 4;

[0031] G gf =0.01AH(φ-φ ga ) / B g Formula 4

[0032] Where: G gf is the free gas reserves, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; B g is the natural gas volume coefficient.

[0033] In the step d, determining the shale gas reserve calculation model refers to determining it by using Formula 5;

[0034] G g =G ga +G gf Formula 5

[0035] Where: G g is shale gas reserves, 10 8 m 3 ; G ga is the adsorbed gas reserve, 10 8 m 3 ; G gf is the free gas reserves, 10 8m 3 .

[0036] In step d, the shale gas reserves refer to the amount of natural gas converted from the adsorbed gas reserves and free gas reserves stored in the shale reservoir to a temperature of 20° C. and a pressure of 0.1 MPa.

[0037] The beneficial effects of the present invention are mainly manifested in the following aspects:

[0038] 1. The present invention first evaluates the maximum possible adsorbed gas volume of shale gas, then assesses the maximum possible pore space occupied by the adsorbed gas based on the adsorbed gas density. After deducting the pore space occupied by bound water, the adsorbed gas reserves are evaluated to obtain a relatively accurate adsorbed gas reserve. Then, after deducting the pore space occupied by the adsorbed gas and bound water, the free gas reserves are evaluated using a volumetric method to obtain a relatively accurate free gas reserve. Finally, an overall shale gas reserve evaluation is performed, greatly improving the accuracy of shale gas reserve evaluation.

[0039] 2. The present invention is simple to operate, low in cost, has sufficient basis and reliable evaluation.

[0040] 3. The present invention deducts the pore space occupied by adsorbed gas, making the calculation of free gas more accurate and the calculation of shale gas reserves more precise.

[0041] 4. The present invention takes into account the relatively high density of adsorbed gas in the reservoir, thereby making the calculation of the pore space occupied by the adsorbed gas more accurate.

[0042] 5. The present invention has high calculation accuracy, can more accurately evaluate resources and reserves, and provide a basis for exploration and development deployment. BRIEF DESCRIPTION OF THE DRAWINGS

[0043] The present invention will be further described below in conjunction with the accompanying drawings and specific embodiments:

[0044] Figure 1 This is the isothermal adsorption curve of dry core shale. DETAILED DESCRIPTION

[0045] Example 1

[0046] A shale gas reserve evaluation method comprises the following steps:

[0047] a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c, determine the calculation model of adsorbed gas density and adsorbed gas-water porosity;

[0048] b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves;

[0049] c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model;

[0050] d. Determine the shale gas reserve calculation model.

[0051] This embodiment is the most basic implementation method. First, the maximum possible adsorbed gas volume of shale gas is evaluated. Then, based on the adsorbed gas density, the maximum possible pore space occupied by the adsorbed gas is assessed. After deducting the pore space occupied by bound water, the adsorbed gas reserves are evaluated to obtain a relatively accurate adsorbed gas reserve. Then, after deducting the pore space occupied by adsorbed gas and bound water, the free gas reserves are evaluated using the volumetric method to obtain a relatively accurate free gas reserve. Finally, an overall shale gas reserve evaluation is performed, which greatly improves the accuracy of shale gas reserve evaluation.

[0052] Example 2

[0053] A shale gas reserve evaluation method comprises the following steps:

[0054] a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity;

[0055] b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves;

[0056] c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model;

[0057] d. Determine the shale gas reserve calculation model.

[0058] In step a, the ground standard temperature and pressure refers to a temperature of 20° C. and a pressure of 0.1 MPa.

[0059] In step a, the maximum adsorption volume per unit is determined based on the formation temperature T and the formation pressure P in the dry core shale isothermal adsorption curve. max .

[0060] In the step a, determining the adsorbed gas density calculation model refers to determining it by formula 1;

[0061] ρ gd =8M g P cr / RT cr Formula 1

[0062] Where: ρ gd is the adsorption density, t / m 3 ;M g is the gas molar mass, g / mol; P cr is the critical pressure of natural gas, MPa; R is the gas constant, which is 8.314 J / (mol.K); T cr is the critical temperature of natural gas, K.

[0063] In the step a, determining the calculation model of the adsorbed gas and water porosity refers to determining it by formula 2;

[0064] φ ga =ΔV max ρ gs ρ c / ρ gd

[0065] If φ ga >φ, then φ ga =φ

[0066] If φ ga <SW i φ, then φ ga =SW i φ Equation 2

[0067] Where: φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; ΔV max is the maximum adsorption volume per unit, m 3 / t;ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 ρ c is the shale density, m 3 / t;ρ gd is the density of adsorbed gas in the formation, t / m 3 ; SW iis the bound water saturation.

[0068] This embodiment is a preferred implementation method, which is simple to operate, low in cost, has sufficient basis and reliable evaluation.

[0069] Example 3

[0070] A shale gas reserve evaluation method comprises the following steps:

[0071] a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity;

[0072] b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves;

[0073] c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model;

[0074] d. Determine the shale gas reserve calculation model.

[0075] In step a, the ground standard temperature and pressure refers to a temperature of 20° C. and a pressure of 0.1 MPa.

[0076] In step a, the maximum adsorption volume per unit is determined based on the formation temperature T and the formation pressure P in the dry core shale isothermal adsorption curve. max .

[0077] In the step a, determining the adsorbed gas density calculation model refers to determining it by formula 1;

[0078] ρ gd =8M g P cr / RT cr Formula 1

[0079] Where: ρ gd is the adsorption density, t / m 3 ;M g is the gas molar mass, g / mol; P cris the critical pressure of natural gas, MPa; R is the gas constant, which is 8.314 J / (mol.K); T cr is the critical temperature of natural gas, K.

[0080] In the step a, determining the calculation model of the adsorbed gas and water porosity refers to determining it by formula 2;

[0081] φ ga =ΔV max ρ gs ρ c / ρ gd

[0082] If φ ga >φ, then φ ga =φ

[0083] If φ ga <SW i φ, then φ ga =SW i φ Equation 2

[0084] Where: φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; ΔV max is the maximum adsorption volume per unit, m 3 / t;ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 ρ c is the shale density, m 3 / t;ρ gd is the density of adsorbed gas in the formation, t / m 3 ; SW i is the bound water saturation.

[0085] In the step b, determining the adsorbed gas reserve calculation model refers to determining it by formula 3;

[0086] G ga =0.01AHρ gd (φ ga -SW i φ) / ρ gs Formula 3

[0087] Where: G ga is the adsorbed gas reserve, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; ρ gd is the density of adsorbed gas in the formation, t / m 3 ;φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; SW iis the bound water saturation; ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 .

[0088] This embodiment is another preferred implementation method, which deducts the pore space occupied by adsorbed gas, making the free gas calculation more accurate and the shale gas reserve calculation more accurate.

[0089] Example 4

[0090] A shale gas reserve evaluation method comprises the following steps:

[0091] a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity;

[0092] b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves;

[0093] c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model;

[0094] d. Determine the shale gas reserve calculation model.

[0095] In step a, the ground standard temperature and pressure refers to a temperature of 20° C. and a pressure of 0.1 MPa.

[0096] In step a, the maximum adsorption volume per unit is determined based on the formation temperature T and the formation pressure P in the dry core shale isothermal adsorption curve. max .

[0097] In the step a, determining the adsorbed gas density calculation model refers to determining it by formula 1;

[0098] ρ gd =8M g P cr / RT cr Formula 1

[0099] Where: ρ gd is the adsorption density, t / m 3;M g is the gas molar mass, g / mol; P cr is the critical pressure of natural gas, MPa; R is the gas constant, which is 8.314 J / (mol.K); T cr is the critical temperature of natural gas, K.

[0100] In the step a, determining the calculation model of the adsorbed gas and water porosity refers to determining it by formula 2;

[0101] φ ga =ΔV max ρ gs ρ c / ρ gd

[0102] If φ ga >φ, then φ ga =φ

[0103] If φ ga <SW i φ, then φ ga =SW i φ Equation 2

[0104] Where: φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; ΔV max is the maximum adsorption volume per unit, m 3 / t;ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 ρ c is the shale density, m 3 / t;ρ gd is the density of adsorbed gas in the formation, t / m 3 ; SW i is the bound water saturation.

[0105] In the step b, determining the adsorbed gas reserve calculation model refers to determining it by formula 3;

[0106] G ga =0.01AHρ gd (φ ga -SW i φ) / ρ gs Formula 3

[0107] Where: G ga is the adsorbed gas reserve, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; ρ gd is the density of adsorbed gas in the formation, t / m 3 ;φga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; SW i is the bound water saturation; ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 .

[0108] In step c, the free gas reserves refer to the free gas reserves stored in the pores of the shale reservoir, converted to the amount of natural gas at a temperature of 20° C. and a pressure of 0.1 MPa.

[0109] In the step c, determining the free gas reserve calculation model refers to determining it by using formula 4;

[0110] G gf =0.01AH(φ-φ ga ) / B g Formula 4

[0111] Where: G gf is the free gas reserves, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; B g is the natural gas volume coefficient.

[0112] This embodiment is another preferred implementation method. Since the higher density of adsorbed gas in the reservoir is taken into consideration, the calculation of the pore space occupied by the adsorbed gas is more accurate.

[0113] Example 5

[0114] A shale gas reserve evaluation method comprises the following steps:

[0115] a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity;

[0116] b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves;

[0117] c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model;

[0118] d. Determine the shale gas reserve calculation model.

[0119] In step a, the ground standard temperature and pressure refers to a temperature of 20° C. and a pressure of 0.1 MPa.

[0120] In step a, the maximum adsorption volume per unit is determined based on the formation temperature T and the formation pressure P in the dry core shale isothermal adsorption curve. max .

[0121] In the step a, determining the adsorbed gas density calculation model refers to determining it by formula 1;

[0122] ρ gd =8M g P cr / RT cr Formula 1

[0123] Where: ρ gd is the adsorption density, t / m 3 ;M g is the gas molar mass, g / mol; P cr is the critical pressure of natural gas, MPa; R is the gas constant, which is 8.314 J / (mol.K); T cr is the critical temperature of natural gas, K.

[0124] In the step a, determining the calculation model of the adsorbed gas and water porosity refers to determining it by formula 2;

[0125] φ ga =ΔV max ρ gs ρ c / ρ gd

[0126] If φ ga >φ, then φ ga =φ

[0127] If φ ga <SW i φ, then φ ga =SW i φ Equation 2

[0128] Where: φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; ΔV max is the maximum adsorption volume per unit, m 3 / t;ρ gsis the density of natural gas at standard surface temperature and pressure, t / m 3 ρ c is the shale density, m 3 / t;ρ gd is the density of adsorbed gas in the formation, t / m 3 ; SW i is the bound water saturation.

[0129] In the step b, determining the adsorbed gas reserve calculation model refers to determining it by formula 3;

[0130] G ga =0.01AHρ gd (φ ga -SW i φ) / ρ gs Formula 3

[0131] Where: G ga is the adsorbed gas reserve, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; ρ gd is the density of adsorbed gas in the formation, t / m 3 ;φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; SW i is the bound water saturation; ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 .

[0132] In step c, the free gas reserves refer to the free gas reserves stored in the pores of the shale reservoir, converted to the amount of natural gas at a temperature of 20° C. and a pressure of 0.1 MPa.

[0133] In the step c, determining the free gas reserve calculation model refers to determining it by using formula 4;

[0134] G gf =0.01AH(φ-φ ga ) / B g Formula 4

[0135] Where: G gf is the free gas reserves, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; B g is the natural gas volume coefficient.

[0136] In the step d, determining the shale gas reserve calculation model refers to determining it by using Formula 5;

[0137] G g =G ga +G gf Formula 5

[0138] Where: G g is shale gas reserves, 10 8 m 3 ; G ga is the adsorbed gas reserve, 10 8 m 3 ; G gf is the free gas reserves, 10 8 m 3 .

[0139] In step d, the shale gas reserves refer to the amount of natural gas converted from the adsorbed gas reserves and free gas reserves stored in the shale reservoir to a temperature of 20° C. and a pressure of 0.1 MPa.

[0140] This embodiment is the best implementation method, and the calculation results are highly accurate, which can more accurately evaluate resources and reserves and provide a basis for exploration and development deployment.

[0141] The present invention is further described in detail below using the Sichuan Basin Oilfield Group as an example. Figure 1 :

[0142] Step 1: Through geological evaluation, the formation temperature T of the target area is obtained to be 60°C and the formation pressure P is 25 MPa; see Figure 1 Through analytical experiments, the isothermal adsorption curve of dry core shale is obtained and the maximum unit adsorption volume ΔV is determined. max 2.29m 3 / t;

[0143] Obtain the molar mass M of natural gas through analytical experiments g is 16.04 g / mol, and the critical pressure of natural gas P cr is 4.642Mpa, the critical temperature of natural gas is T cr is 191.05K, determine the adsorbed gas density ρ gd ;

[0144] ρ gd =8M g P cr / RT cr =0.375t / m 3 ;

[0145] Obtain the shale density ρ of the target area through geological evaluation c 2.500t / m 3, the shale reservoir porosity φ is 0.035, and the irreducible water saturation SW i is 0.12; through analytical experiments, the density of natural gas at standard temperature and pressure on the ground is obtained gs 0.717×10 -3 t / m 3 , and then determine the adsorption porosity φ ga ;

[0146] φ ga =ΔV max ρ gs ρ c / ρ gd =0.011;

[0147] Since φ=0.035, SW i =0.12, SW i φ<φ ga <φ, so φ ga =0.007;

[0148] Step 2: Through geological evaluation, the distribution area of ​​shale reservoir in the target area is obtained as A, which is 100km 2 , the shale reservoir thickness H is 25m, the shale reservoir porosity φ is 0.035, and the irreducible water saturation SW i is 0.12; through analytical experiments, the density of natural gas at standard temperature and pressure on the ground is obtained gs 0.717×10 -3 t / m 3 , determine the adsorbed gas reserves G ga ;

[0149] G ga =0.01AHρ gd (φ ga -SW i φ) / ρ gs =88.91×10 8 m 3 ;

[0150] Step 3: Through geological evaluation, obtain the shale reservoir distribution area A of 100km 2 The shale reservoir thickness H is 25m, and the shale reservoir porosity φ is 0.035. Through analytical experiments, the natural gas volume coefficient B is obtained. g is 0.00478, and the free gas reserves G is determined. gf ;

[0151] G gf =0.01AH(φ-φ ga ) / B g =20.92×10 8 m 3;

[0152] Step 4: Finally determine the shale gas reserves G g ;

[0153] G g =G ga +G gf =109.83×10 8 m 3 .

[0154] The calculation results show that the shale gas reserves in the area are 10.983 billion cubic meters, of which the adsorbed gas reserves are 8.891 billion cubic meters and the free gas reserves are 2.092 billion cubic meters.

[0155] The dry core shale isothermal adsorption curve described in the present invention refers to the equilibrium adsorption amount at a certain temperature, which depends on the pressure of the gas. The adsorption amount increases with increasing pressure. The curve showing the change of adsorption amount with pressure at a constant temperature is called an isothermal adsorption curve. The isothermal adsorption curve can reflect the adsorption characteristics of the solid surface. Commonly used instruments are the ISO-200 isothermal adsorption instrument and the American TER-TEK ISO-300 automatic isothermal adsorption instrument. The solid here refers to the dried shale core, and the gas refers to hydrocarbon natural gas. The horizontal axis of the curve is generally pressure, and the vertical axis is generally adsorption amount. The temperature of each curve is the same. Generally, after the pressure increases to a certain value, the adsorption amount at the same temperature approaches a maximum value V. L , that is, the maximum adsorption capacity; adsorption capacity V L Reach V L / 2 corresponding to the pressure value, called the Langmuir pressure P L , which affects the morphological parameters of the adsorption isotherm and reflects the difficulty of shale gas desorption. The lower the value, the easier the desorption and the more favorable the development.

Claims

1. A shale gas reserve evaluation method, characterized in that: The following steps are involved: a. Obtain the formation temperature T, formation pressure P, dry core shale isothermal adsorption curve, and natural gas molar mass M in the target area. g , natural gas critical pressure P cr , natural gas critical temperature T cr , the density of natural gas at standard surface temperature and pressure ρ gs , shale density ρ c , determine the calculation model of adsorbed gas density and adsorbed gas-water porosity; b. Obtain the distribution area A, thickness H, porosity φ, and irreducible water saturation SW of the shale reservoir in the target area. i , the density of natural gas at standard surface temperature and pressure ρ gs , determine the calculation model of adsorbed gas reserves; c. Obtain the distribution area A of the shale reservoir, the thickness H of the shale reservoir, and the natural gas volume coefficient B in the target area. g , determine the free gas reserves calculation model; d. Determine the shale gas reserve calculation model; In step a, the maximum adsorption volume per unit is determined based on the formation temperature T and the formation pressure P in the dry core shale isothermal adsorption curve. max ; In the step a, determining the adsorbed gas density calculation model refers to determining it by formula 1; ρ gd =8M g P cr / RT cr Formula 1 Where: ρ gd is the adsorption density, t / m 3 ; M g is the gas molar mass, g / mol; P cr is the critical pressure of natural gas, MPa; R is the gas constant, which is 8.314 J / (mol.K); T cr is the critical temperature of natural gas, K; In the step a, determining the calculation model of the adsorbed gas and water porosity refers to determining it by formula 2; f ga =ΔV max r gs r c / r gd If φ ga >φ, then φ ga =φ If φ ga <SW i φ, then φ ga =SW i φ formula 2 Where: φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; ΔV max is the maximum adsorption volume per unit, m 3 / t;ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 ; ρ c is the shale density, m 3 / t;ρ gd is the density of adsorbed gas in the formation, t / m 3 ; SW i is the bound water saturation.

2. The shale gas reserve evaluation method according to claim 1, characterized in that: In step a, the ground standard temperature and pressure refers to a temperature of 20° C. and a pressure of 0.1 MPa.

3. The shale gas reserve evaluation method according to claim 1, characterized in that: In the step b, determining the adsorbed gas reserve calculation model refers to determining it by formula 3; G ga =0.01AHp gd (f) ga -SW i f) / r gs formula 3 Where: G ga is the adsorbed gas reserve, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; ρ gd is the density of adsorbed gas in the formation, t / m 3 ; φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; SW i is the bound water saturation; ρ gs is the density of natural gas at standard surface temperature and pressure, t / m 3 .

4. The shale gas reserve evaluation method according to claim 1, characterized in that: In step c, the free gas reserves refer to the free gas reserves stored in the pores of the shale reservoir, converted to the amount of natural gas at a temperature of 20° C. and a pressure of 0.1 MPa.

5. The shale gas reserve evaluation method according to claim 1, characterized in that: In the step c, determining the free gas reserves calculation model refers to determining it by using formula 4; G gf =0.01AH(φ-φ) ga ) / B g formula 4 Where: G gf is the free gas reserves, 10 8 m 3 ; A is the distribution area of ​​shale reservoir, km 2 ; H is the thickness of shale reservoir, m; φ ga is the adsorbed gas and water porosity; φ is the shale reservoir porosity; B g is the natural gas volume coefficient.

6. The shale gas reserve evaluation method according to claim 1, characterized in that: In the step d, determining the shale gas reserve calculation model refers to determining it by using Formula 5; G g =G ga +G gf Formula 5 Where: G g is shale gas reserves, 10 8 m 3 ; G ga is the adsorbed gas reserve, 10 8 m 3 ; G gf is the free gas reserves, 10 8 m 3 .

7. The shale gas reserve evaluation method according to claim 1, characterized in that: In step d, the shale gas reserves refer to the amount of natural gas converted from the adsorbed gas reserves and free gas reserves stored in the shale reservoir to a temperature of 20° C. and a pressure of 0.1 MPa.

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