Method for determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data

Abstract

The present invention provides a method for determining shale oil recovery using mercury injection and mercury removal and rock compression data, comprising: step 1, determining basic parameters of a shale reservoir; step 2, conducting a mercury injection and mercury removal experiment and collating the data; step 3, establishing a fluid self-drive model and calculating the fluid self-drive rate; step 4, conducting a rock compression experiment and collating the data; step 5, establishing a rock compression drive model and calculating the rock compression drive rate; and step 6, establishing a total recovery rate calculation model and calculating the total shale oil recovery rate. This method for determining shale oil recovery using mercury injection and mercury removal and rock compression data utilizes high-pressure mercury injection and mercury removal technology and rock compression technology, combined with basic parameters of shale reservoirs, to divide the shale oil production process into two parts: fluid self-drive and rock compression drive. This method can be used to accurately and quantitatively evaluate the recovery rate or mobilization rate of shale oil and is easy to promote and apply.

Description

Technical Field

[0001] The present invention relates to the technical fields of petroleum geological exploration and oil and gas development, and in particular to a method for determining shale oil recovery rate by utilizing mercury injection-mercury withdrawal and rock compression data. Background Art

[0002] Shale oil recovery rate or mobilization rate is a key parameter in shale oil exploration and development. However, due to the relatively late development of shale oil exploration technology, the dense reservoirs within shale, the complex pore structure, and the demanding production conditions of shale oil, there is still a lack of effective systematic evaluation methods for shale oil recovery rate or mobilization rate. However, shale high-pressure mercury injection and rock compression testing technologies are relatively mature. Therefore, this paper aims to develop a shale oil recovery rate or mobilization rate evaluation method by combining high-pressure mercury injection and mercury withdrawal and rock compression techniques with basic shale reservoir parameters.

[0003] Invention application number 201310160959.7 discloses a method for evaluating the pore water characteristics and occurrence state of tight sandstone reservoirs. The method comprises: converting nuclear magnetic T2 spectra into pseudo-capillary pressure curves through core mercury injection and nuclear magnetic resonance experiments; obtaining cumulative permeability contributions through core mercury injection experiments, and establishing a reservoir pore throat space effectiveness classification standard based on the cumulative permeability contributions; and, based on the pore throat space effectiveness classification standard, calculating the clay bound water volume, unmovable capillary bound water volume, constrained capillary bound water volume, and movable fluid volume from the pseudo-capillary pressure curve to evaluate the pore water characteristics and occurrence state of tight sandstone reservoirs. This method discloses the movable fluid volume of tight sandstone reservoirs and does not address the technical content of the present invention regarding shale oil mobility.

[0004] The published paper, "Method for Calculating Movable Fluid Saturation in Tight Oil Reservoirs" (Petroleum Experimental Geology, November 2014), states that the movable fluid saturation of tight oil reservoirs can be calculated using the total mercury injection saturation parameter from constant-rate mercury injection. The mercury injection saturation at 7.0 MPa high-pressure mercury injection is equivalent to the total mercury injection saturation from constant-rate mercury injection, thus proposing a method for calculating movable fluid saturation in tight oil using high-pressure mercury injection data. This paper does not address the technical method for determining shale oil recovery using high-pressure mercury injection-mercury withdrawal curves and rock compressibility, as described in the present invention.

[0005] A paper published in the journal "Microscopic Pore-Throat and Movable Fluid Variation Characteristics of the Xu 4 Member Tight Sandstone Reservoir in Xinchang, Western Sichuan" (Petroleum Experimental Geology, January 2014) describes the quantitative analysis of these characteristics using constant-rate mercury injection and nuclear magnetic resonance (NMR) experiments. This paper does not address the use of high-pressure mercury injection-ejection curves or rock compression to determine shale oil recovery or mobility.

[0006] The above existing technologies are significantly different from the present invention and fail to solve the technical problem we want to solve. Therefore, we have invented a new method for determining shale oil recovery rate using mercury injection-mercury withdrawal and rock compression data. Summary of the Invention

[0007] The purpose of the present invention is to provide a method for determining shale oil recovery rate using mercury injection-mercury withdrawal and rock compression data, which provides an effective technical means for calculating shale oil movable resources and determining the recoverable coefficient.

[0008] The object of the present invention can be achieved by the following technical measures: a method for determining shale oil recovery rate using mercury injection-mercury removal and rock compression data, the method for determining shale oil recovery rate using mercury injection-mercury removal and rock compression data comprising:

[0009] Step 1: Determine the basic parameters of shale oil reservoirs;

[0010] Step 2: Conduct mercury injection-mercury stripping experiments and organize data;

[0011] Step 3: Establish a fluid self-driving model and calculate the fluid self-driving rate;

[0012] Step 4: Conduct rock compression experiments and organize data;

[0013] Step 5: Establish a rock compression driving model and calculate the rock compression driving rate;

[0014] Step 6: Establish a total recovery calculation model and calculate the total recovery of shale oil.

[0015] The purpose of the present invention can also be achieved by the following technical measures:

[0016] In step 1, the basic parameters of the shale reservoir are determined, including the initial formation pressure of the shale reservoir, the depletion formation pressure of the shale reservoir, the porosity of the shale reservoir, the initial oil saturation of the shale reservoir, and the compressibility coefficient of the crude oil in the shale reservoir.

[0017] In step 2, a typical shale sample of a shale reservoir is selected for a high-pressure mercury injection-mercury withdrawal experiment. The high-pressure mercury injection-mercury withdrawal experiment requires that the maximum mercury injection pressure be at least 5 MPa higher than the initial pressure of the reservoir, and the maximum mercury injection pressure is not less than 30 MPa.

[0018] In step 3, a fluid self-drive model is established and the fluid self-drive rate is calculated based on the basic parameters of the shale reservoir, including the initial formation pressure of the shale reservoir, the production depletion pressure of the shale reservoir, the initial oil saturation of the shale reservoir, the compressibility of shale oil, and the mercury saturation at the production depletion pressure of the reservoir in the mercury withdrawal curve.

[0019] In step 3, the formula for calculating the fluid self-driving rate is:

[0020]

[0021] In formula (1), E f is the fluid self-driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0022] In step 4, a rock compression experiment is conducted under high pressure conditions to establish a relationship between rock volume and rock effective stress, and to determine the volume compression coefficient of the rock, which is the compression coefficient between the effective stress of the initial reservoir and the effective stress at production depletion.

[0023] In step 5, a rock compression driving model is established and the rock compression driving rate is calculated based on the basic parameters of the shale reservoir, including the initial formation pressure of the shale reservoir, the production depletion pressure of the shale reservoir, the initial oil saturation of the shale reservoir, the compressibility of the rock, the compressibility of the oil and the porosity of the shale reservoir.

[0024] In step 5, the rock compression drive rate is calculated as:

[0025]

[0026] In formula (2), E c is the rock compression driving rate, decimal; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; S O is the initial oil saturation of the reservoir, %; ΔP is the difference between the reservoir production depletion pressure and the initial fluid pressure of the reservoir, MPa.

[0027] In step 6, the total shale oil recovery factor includes the fluid self-drive factor and the rock compression drive factor, which is calculated as follows:

[0028]

[0029] In formula (3), E T is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E cis the rock compression driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0030] The method for determining shale oil recovery using mercury injection and mercury withdrawal and rock compression data, as disclosed herein, utilizes mercury injection and mercury withdrawal experimental techniques, rock compression experimental techniques, and basic shale reservoir parameters to determine shale oil recovery, providing an effective technical means for calculating shale oil movable resources and determining recoverability coefficients. By utilizing high-pressure mercury injection and mercury withdrawal techniques and rock compression techniques, combined with basic shale reservoir parameters, the method divides the shale oil production process into two components: fluid self-driven energy and rock compression-driven energy. This method can be used to accurately and quantitatively evaluate shale oil recovery or mobilization efficiency, and is readily applicable. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] Figure 1 A flowchart of a specific embodiment of the method for determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data of the present invention;

[0032] Figure 2 Schematic diagram of determining a fluid self-propulsion model using mercury injection-ejection data in one embodiment of the present invention. DETAILED DESCRIPTION

[0033] It should be noted that the following detailed descriptions are exemplary and intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the art to which the present invention belongs.

[0034] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is intended to include the plural form. In addition, it should be understood that when the terms "comprise" and / or "include" are used in this specification, they indicate the presence of features, steps, operations and / or combinations thereof.

[0035] The present invention's method for determining shale oil recovery using mercury injection, mercury withdrawal, and rock compression data divides the shale oil produced by shale reservoir fluid into two parts: one is the self-driven amount of high-pressure fluid within the rock, and the other is the driven amount generated by rock compression. It mainly includes the following steps:

[0036] Step 101: Determine basic parameters of the shale reservoir. Determine basic parameters of the shale reservoir, including initial formation pressure of the shale reservoir, depletion formation pressure of the shale reservoir during production, porosity of the shale reservoir, initial oil saturation of the shale reservoir, and compressibility of crude oil in the shale reservoir.

[0037] Step 201, mercury injection-mercury withdrawal experiment and data collation; For the mercury injection-mercury withdrawal experiment and data collation, a typical shale sample from a shale reservoir needs to be selected for a high-pressure mercury injection-mercury withdrawal experiment. The high-pressure mercury injection-mercury withdrawal experiment requires that the maximum mercury injection pressure be at least 5 MPa higher than the initial reservoir pressure, and the maximum mercury injection pressure is not less than 30 MPa.

[0038] Step 301: Calculate the fluid self-drive model and drive rate. The required parameters for the fluid self-drive model and drive rate calculation formula include the initial formation pressure of the shale reservoir, the production depletion pressure of the shale reservoir, the initial oil saturation of the shale reservoir, the compressibility of the shale oil, and the mercury saturation at the production depletion pressure of the reservoir in the mercury withdrawal curve. The model and calculation formula are as follows:

[0039]

[0040] In formula (1), E f is the fluid self-driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0041] Step 202, rock compression test and data collation: rock compression test and data collation, conduct rock compression test under high pressure conditions, establish the relationship between rock volume and rock effective stress, and determine the volume compression coefficient of the rock, which is the compression coefficient between the effective stress of the initial oil reservoir and the effective stress at production depletion.

[0042] Step 302: Rock compression drive model and drive rate calculation. The rock compression drive model and drive rate calculation include the following parameters: initial formation pressure of the shale reservoir, shale reservoir production depletion pressure, initial oil saturation of the shale reservoir, rock compressibility, oil compressibility, and shale reservoir porosity. The model and calculation formula are as follows:

[0043]

[0044] In formula (2), E c is the rock compression driving rate, decimal; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; S O is the initial oil saturation of the reservoir, %; ΔP is the difference between the reservoir production depletion pressure and the initial fluid pressure of the reservoir, MPa.

[0045] Step 401: Total recovery calculation model and calculation.

[0046] The total recovery calculation model and calculation include the fluid self-driven rate and rock compression driven rate, and the calculation formula is as follows:

[0047]

[0048] In formula (3), E T is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E c is the rock compression driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0049] The following are several specific embodiments of the present invention.

[0050] Example 1:

[0051] In a specific embodiment 1 of the present invention, Figure 1 As shown, Figure 1 The present invention is a flow chart of a method for determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data.

[0052] This method of determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data mainly quantifies the elastic production of oil in shale reservoirs into two parts: one is the fluid self-driven production, and the other is the rock compression-driven production. The total production is the sum of the above two parts. That is:

[0053] E T =E f +E c (1)

[0054] In formula (1), E T is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E c is the rock compression drive rate, a decimal.

[0055] The method for determining shale oil recovery rate using mercury injection-mercury withdrawal and rock compression data mainly includes the following steps:

[0056] Step 101, determining basic parameters of the shale oil reservoir, including the initial formation pressure of the shale oil reservoir, the depletion formation pressure of the shale oil reservoir during production, the porosity of the shale oil reservoir, the initial oil saturation of the shale oil reservoir, the compressibility coefficient of the crude oil in the shale oil reservoir, etc.

[0057] Step 201: Mercury injection and mercury removal experiments and data compilation. A typical shale reservoir sample must be selected for a high-pressure mercury injection and mercury removal experiment, or data from these experiments must be collected and compiled. The maximum mercury injection pressure for these experiments must be at least 5 MPa higher than the initial reservoir pressure to fully simulate the fluid-driven pressure drop process. Furthermore, the maximum mercury injection pressure must be no less than 30 MPa to ensure mercury enters rock pores or fractures of a certain diameter. Step 301 is then executed.

[0058] Step 301: Calculate the fluid self-propulsion model and propulsion rate using a mercury withdrawal curve to virtually calculate the fluid self-propulsion rate. Required parameters include the initial formation pressure of the shale reservoir, the shale reservoir production depletion pressure, the initial oil saturation of the shale reservoir, the compressibility of the shale oil, and the mercury saturation at the reservoir production depletion pressure as measured by the mercury withdrawal curve. The model and calculation formula are as follows:

[0059]

[0060] Formula (2) is further transformed into:

[0061]

[0062] In formula (2) and formula (3), E f is the fluid self-driving rate, decimal; V1, the volume of the calculated unit rock, m 3 ;SO is the initial oil saturation of the shale reservoir, %; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; ρ i and ρ e is the initial crude oil density of the shale reservoir and the density at production depletion pressure, g / cm 3 ; is the porosity of the shale reservoir, a decimal. C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0063] Step 202, rock compression test and data collation, conducts rock compression test under high pressure conditions or collate the experimental data, establishes the relationship between rock volume and rock effective stress, and determines the volume compression coefficient of the rock, which is the compression coefficient between the effective stress of the initial reservoir and the effective stress at production depletion.

[0064] Step 302: Calculate the rock compression drive model and drive rate. The rock compression drive rate is the compression of the rock volume caused by a decrease in reservoir pressure and an increase in effective stress. The rock volume compression is combined with the crude oil density to calculate the compression drive. The model and calculation formula include the following parameters: initial formation pressure of the shale reservoir, production depletion pressure of the shale reservoir, initial oil saturation of the shale reservoir, rock compressibility, oil compressibility, and porosity of the shale reservoir. The model and calculation formula are as follows:

[0065]

[0066] In formula (4), E c is the rock compression driving rate, decimal; V1 is the rock volume of the calculation unit, m 3 ; V2 is the volume of the rock unit after compression due to the increase of effective stress, m 3 ; is the porosity of shale oil reservoir, decimal; S O is the initial oil saturation of the shale reservoir, %; ρ i is the initial crude oil density of the shale reservoir and the density at production depletion pressure, g / cm 3 ρ m is the average density of oil in the rock during rock compression, g / cm 3 .

[0067] Substituting the rock compressibility coefficient and crude oil compressibility coefficient into formula (4), the following formula for calculating the compression drive rate is obtained:

[0068]

[0069] In formula (5), E c is the rock compression driving rate, decimal; C r is the volume compressibility of rock, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa, C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 , is the porosity of shale oil reservoir, decimal; S O is the initial oil saturation of shale reservoir, %

[0070] Step 401, the total recovery calculation model and calculation include the fluid self-driven rate and rock compression driven rate, and the calculation formula is as follows:

[0071]

[0072] In formula (6), E T is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E c is the rock compression driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0073] Example 2:

[0074] In a specific embodiment 2 of the present invention, as Figure 1 As shown, Figure 1 The present invention is a flow chart of a method for determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data.

[0075] This method of determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data mainly quantifies the elastic production of oil in shale reservoirs into two parts: one is the fluid self-driven production, and the other is the rock compression-driven production. The total production is the sum of the above two parts. That is:

[0076] E T =E f +E c (1)

[0077] In formula (1), ET is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E c is the rock compression drive rate, a decimal.

[0078] The method for determining shale oil recovery rate using mercury injection-mercury withdrawal and rock compression data mainly includes the following steps:

[0079] Step 101, determining basic parameters of the shale reservoir, including the initial formation pressure of the shale reservoir, the depletion formation pressure of the shale reservoir during production, the porosity of the shale reservoir, the initial oil saturation of the shale reservoir, the comprehensive compressibility coefficient of the shale reservoir formation fluid, etc.

[0080] Step 201: Mercury injection and mercury removal experiments and data compilation. A typical shale reservoir sample must be selected for a high-pressure mercury injection and mercury removal experiment, or data from these experiments must be collected and compiled. The maximum mercury injection pressure for these experiments must be at least 5 MPa higher than the initial reservoir pressure to fully simulate the fluid-driven pressure drop process. Furthermore, the maximum mercury injection pressure must be no less than 30 MPa to ensure mercury enters rock pores or fractures of a certain diameter. Step 301 is then executed.

[0081] Step 301: Calculate the fluid self-propulsion model and propulsion rate. The fluid self-propulsion model uses a mercury withdrawal curve to virtually calculate the fluid self-propulsion rate. Required parameters include the initial formation pressure of the shale reservoir, the shale reservoir production depletion pressure, the initial oil saturation of the shale reservoir, the comprehensive compressibility of the shale reservoir's formation fluid, and the mercury saturation at the reservoir production depletion pressure as measured by the mercury withdrawal curve. The model and calculation formula are as follows:

[0082]

[0083] Formula (2) is further transformed into:

[0084]

[0085] In formula (2) and formula (3), E f is the fluid self-driving rate, decimal; V1, the volume of the calculated unit rock, m 3 ;S O is the initial oil saturation of the shale reservoir, %; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; ρ i and ρ e is the initial crude oil density of the shale reservoir and the density at production depletion pressure, g / cm 3 ; is the porosity of the shale reservoir, a decimal. C f is the comprehensive compressibility coefficient of formation fluid, MPa -1; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0086] Step 202, rock compression test and data collation, conducts rock compression test under high pressure conditions or collate the experimental data, establishes the relationship between rock volume and rock effective stress, and determines the volume compression coefficient of the rock, which is the compression coefficient between the effective stress of the initial reservoir and the effective stress at production depletion.

[0087] Step 302: Calculate the rock compression drive model and drive rate. The rock compression drive rate is the total rock volume compression caused by a decrease in reservoir pressure and an increase in effective stress. The rock volume compression is combined with the crude oil density to calculate the compression drive. The model and calculation formula include the following parameters: initial formation pressure of the shale reservoir, production depletion pressure of the shale reservoir, initial oil saturation of the shale reservoir, rock compressibility, comprehensive formation fluid compressibility, and shale reservoir porosity. The model and calculation formula are as follows:

[0088]

[0089] In formula (4), E c is the rock compression driving rate, decimal; V1 is the rock volume of the calculation unit, m 3 ; V2 is the volume of the rock unit after compression due to the increase of effective stress, m 3 ; is the porosity of shale oil reservoir, decimal; S O is the initial oil saturation of the shale reservoir, %; ρ i is the initial crude oil density of the shale reservoir and the density at production depletion pressure, g / cm 3 ρ m is the average density of oil in the rock during rock compression, g / cm 3 .

[0090] Substituting the rock compressibility coefficient and the formation fluid comprehensive compressibility coefficient into formula (4), the following formula for calculating the compression driving rate is obtained:

[0091]

[0092] In formula (5), E c is the rock compression driving rate, decimal; C r is the volume compressibility of rock, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa, C tf is the comprehensive compressibility coefficient of formation fluid, MPa -1 , is the porosity of shale oil reservoir, decimal; S Ois the initial oil saturation of shale reservoir, %

[0093] Step 401, the total recovery calculation model and calculation include the fluid self-driven rate and rock compression driven rate, and the calculation formula is as follows:

[0094]

[0095] In formula (6), E T is the total driving rate, decimal; C tf is the fluid self-driving rate, decimal; E C is the rock compression driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C r is the volume compression coefficient of rock, MPa-1; C tf is the comprehensive compressibility coefficient of formation fluid, MPa-1; is the porosity of the reservoir, a decimal; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0096] Example 3:

[0097] In a specific embodiment 3 of the present invention, as Figure 1 As shown, Figure 1 The present invention is a flow chart of a method for determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data.

[0098] This method of determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data mainly quantifies the elastic production of oil in shale reservoirs into two parts: one is the fluid self-driven production, and the other is the rock compression-driven production. The total production is the sum of the above two parts. That is:

[0099] E T =E f +E c (1)

[0100] In formula (1), E T is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E c is the rock compression drive rate, a decimal.

[0101] The method for determining shale oil recovery rate using mercury injection-mercury withdrawal and rock compression data mainly includes the following steps:

[0102] Step 101, determining basic parameters of the shale oil reservoir, including the initial formation pressure of the shale oil reservoir, the depletion formation pressure of the shale oil reservoir during production, the porosity of the shale oil reservoir, the initial oil saturation of the shale oil reservoir, the compressibility coefficient of the crude oil in the shale oil reservoir, etc.

[0103] Step 201: Mercury injection and mercury removal experiments and data compilation. A typical shale reservoir sample must be selected for a high-pressure mercury injection and mercury removal experiment, or data from these experiments must be collected and compiled. The maximum mercury injection pressure for these experiments must be at least 5 MPa higher than the initial reservoir pressure to fully simulate the fluid-driven pressure drop process. Furthermore, the maximum mercury injection pressure must be no less than 30 MPa to ensure mercury enters rock pores or fractures of a certain diameter. Step 301 is then executed.

[0104] Step 301: Calculate the fluid self-propulsion model and propulsion rate using a mercury withdrawal curve to virtually calculate the fluid self-propulsion rate. Required parameters include the initial formation pressure of the shale reservoir, the shale reservoir production depletion pressure, the initial oil saturation of the shale reservoir, the compressibility of the shale oil, and the mercury saturation at the reservoir production depletion pressure as measured by the mercury withdrawal curve. The model and calculation formula are as follows:

[0105]

[0106] Formula (2) is further transformed into:

[0107]

[0108] In formula (2) and formula (3), E f is the fluid self-driving rate, decimal; V1, the volume of the calculated unit rock, m 3 ;S O is the initial oil saturation of the shale reservoir, %; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; ρ i and ρ e is the initial crude oil density of the shale reservoir and the density at production depletion pressure, g / cm 3 ; is the porosity of the shale reservoir, a decimal. C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0109] Step 202, rock compression test and data collation, conducts rock compression test under high pressure conditions or collate the experimental data, establishes the relationship between rock volume and rock effective stress, and determines the volume compression coefficient of the rock, which is the compression coefficient between the effective stress of the initial reservoir and the effective stress at production depletion.

[0110] Step 302: Calculate the rock compression drive model and drive rate. The rock compression drive rate is the compression of the rock volume caused by a decrease in reservoir pressure and an increase in effective stress. The rock volume compression is combined with the crude oil density to calculate the compression drive. The model and calculation formula include the following parameters: initial formation pressure of the shale reservoir, production depletion pressure of the shale reservoir, initial oil saturation of the shale reservoir, rock pore volume compressibility, oil compressibility, and shale reservoir porosity. The model and calculation formula are as follows:

[0111]

[0112] In formula (4), E c is the rock compression driving rate, decimal; V1 is the rock volume of the calculation unit, m 3 ; V2 is the volume of the rock unit after compression due to the increase of effective stress, m 3 ; is the porosity of shale oil reservoir, decimal; S O is the initial oil saturation of the shale reservoir, %; ρ i is the initial crude oil density of the shale reservoir and the density at production depletion pressure, g / cm 3 ρ m is the average density of oil in the rock during rock compression, g / cm 3 .

[0113] Substituting the rock pore volume compressibility coefficient and crude oil compressibility coefficient into formula (4) yields the following formula for calculating the compression driving rate:

[0114]

[0115] In formula (5), E c is the rock compression driving rate, decimal; CP is the pore volume compressibility coefficient of the rock, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa, C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 ;S O is the initial oil saturation of shale reservoir, %

[0116] Step 401, the total recovery calculation model and calculation include the fluid self-driven rate and rock compression driven rate, and the calculation formula is as follows:

[0117]

[0118] In formula (6), E T is the total driving rate, decimal; E fis the fluid self-driving rate, decimal; E c is the rock compression driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C P is the rock pore volume compressibility coefficient, MPa-1; C f is the compressibility coefficient of crude oil, MPa-1; is the porosity of the reservoir, a decimal; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

[0119] Figure 2 The schematic diagram of a fluid self-driving model determined by mercury injection-mercury withdrawal data in a specific embodiment of the present invention is shown in FIG. Where Pi is the initial pressure of the shale reservoir; Pe is the production depletion pressure of the shale reservoir; S Hg1 is the mercury saturation at the initial pressure of the shale oil reservoir on the mercury withdrawal curve; S Hg2 is the mercury saturation at the production depletion pressure of the shale oil reservoir on the mercury withdrawal curve. Figure 2 It can be seen that on the mercury withdrawal curve, from the initial reservoir pressure to the depletion pressure, the self-driven amount of mercury is S Hg1 With S Hg2 The difference between the mercury self-drive capacity and the crude oil coefficient can be used to determine the reservoir fluid self-drive capacity, and the rock compression drive capacity can be determined by combining the rock compression capacity and the oil compression coefficient.

[0120] Finally, it should be noted that the above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art may modify the technical solutions described in the aforementioned embodiments or substitute equivalents for some of the technical features therein. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention shall be included within the scope of protection of the present invention.

[0121] Except for the technical features described in the specification, all other technical features are known technologies to those skilled in the art.

Claims

1. A method for determining shale oil recovery using mercury injection-mercury withdrawal and rock compression data, characterized in that: The method for determining shale oil recovery rate using mercury injection-mercury withdrawal and rock compression data includes: Step 1: Determine the basic parameters of shale oil reservoirs; Step 2: Conduct mercury injection-mercury stripping experiments and organize data; Step 3: Establish a fluid self-driving model and calculate the fluid self-driving rate; Step 4: Conduct rock compression experiments and organize data; Step 5: Establish a rock compression driving model and calculate the rock compression driving rate; Step 6: Establish a total recovery calculation model and calculate the total recovery of shale oil; In step 3, the formula for calculating the fluid self-driving rate is: In formula (1), E f is the fluid self-driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S o is the initial oil saturation of the reservoir, %; C f is the compressibility coefficient of shale oil reservoir crude oil, MPa -1 ; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa; In step 5, the rock compression drive rate is calculated as: In formula (2), E c is the rock compression driving rate, decimal; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; S O is the initial oil saturation of the reservoir, %; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa; In step 6, the total shale oil recovery factor includes the fluid self-drive factor and the rock compression drive factor, which is calculated as follows: In formula (3), E T is the total driving rate, decimal; E f is the fluid self-driving rate, decimal; E c is the rock compression driving rate, decimal; S Hg2 is the mercury saturation at the depletion pressure of the reservoir on the mercury withdrawal curve, %; S O is the initial oil saturation of the reservoir, %; C r is the volume compressibility of rock, MPa -1 ; C f is the compressibility coefficient of crude oil, MPa -1 ; is the porosity of the reservoir, a decimal; ΔP is the difference between the reservoir production depletion pressure and the reservoir initial fluid pressure, MPa.

2. The method for determining shale oil recovery using mercury injection-mercury stripping and rock compression data according to claim 1, characterized in that: In step 1, the basic parameters of the shale reservoir are determined, including the initial formation pressure of the shale reservoir, the depletion formation pressure of the shale reservoir, the porosity of the shale reservoir, the initial oil saturation of the shale reservoir, and the compressibility coefficient of the crude oil in the shale reservoir.

3. The method for determining shale oil recovery using mercury injection-mercury stripping and rock compression data according to claim 1, characterized in that: In step 2, a typical shale sample of a shale reservoir is selected for a high-pressure mercury injection-mercury withdrawal experiment. The high-pressure mercury injection-mercury withdrawal experiment requires that the maximum mercury injection pressure be at least 5 MPa higher than the initial pressure of the reservoir, and the maximum mercury injection pressure is not less than 30 MPa.

4. The method for determining shale oil recovery using mercury injection-mercury stripping and rock compression data according to claim 1, wherein: In step 3, a fluid self-drive model is established and the fluid self-drive rate is calculated based on the basic parameters of the shale reservoir, including the initial formation pressure of the shale reservoir, the production depletion pressure of the shale reservoir, the initial oil saturation of the shale reservoir, the compressibility of shale oil, and the mercury saturation at the production depletion pressure of the reservoir in the mercury withdrawal curve.

5. The method for determining shale oil recovery using mercury injection-mercury stripping and rock compression data according to claim 1, wherein: In step 4, a rock compression experiment is conducted under high pressure conditions to establish a relationship between rock volume and rock effective stress, and to determine the volume compression coefficient of the rock, which is the compression coefficient between the effective stress of the initial reservoir and the effective stress at production depletion.

6. The method for determining shale oil recovery using mercury injection-mercury stripping and rock compression data according to claim 1, wherein: In step 5, a rock compression driving model is established and the rock compression driving rate is calculated based on the basic parameters of the shale reservoir, including the initial formation pressure of the shale reservoir, the production depletion pressure of the shale reservoir, the initial oil saturation of the shale reservoir, the compressibility of the rock, the compressibility of the oil and the porosity of the shale reservoir.

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