Method for determining viscosity of shale oil

Abstract

This invention relates to the field of oil and gas exploration and development, and discloses a method for determining the viscosity of shale oil. The method includes: determining the intrinsic permeability of a shale sample based on its gas permeability; calculating the characteristic pore throat size of the shale sample based on its intrinsic permeability and porosity; determining the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone based on the wettability characteristics of the shale sample; calculating the viscosity of the aqueous phase in the shale oil within the shale based on the viscosity of the aqueous phase in the adsorption zone and the characteristic pore throat size, and calculating the viscosity of the oil phase in the shale oil within the shale based on the viscosity of the oil phase in the adsorption zone and the characteristic pore throat size. The shale oil viscosity determined by this invention, considering the influence of nanoscale spatial confinement on viscosity, can be used as an input parameter for shale oil numerical simulation, improving the accuracy of the simulation and thus ensuring the effective development of shale oil.

Description

Technical Field

[0001] This invention relates to the field of oil and gas exploration and development technology, and specifically to a method for determining the viscosity of shale oil. Background Technology

[0002] In the field of shale oil development, numerical simulation is the foundation for designing oilfield exploitation plans. Accurate input parameters are crucial for conducting accurate and effective numerical simulations.

[0003] The nanoscale pores in shale oil reservoirs constitute the primary storage space and seepage channels for shale oil. During flow through these nanopores, shale oil experiences a confinement effect, resulting in significantly different seepage characteristics compared to conventional oil reservoirs. However, shale oil viscosity, a key input parameter in numerical simulations, is currently mostly derived from bulk viscosity measurements obtained at the surface, neglecting the nanoscale confinement effect. Consequently, the shale oil viscosity input for numerical simulations is inaccurate, hindering the effective development of shale oil. Summary of the Invention

[0004] The purpose of this invention is to overcome the problem that the input parameter of shale oil viscosity in the numerical simulation of shale oil in the existing technology is inaccurate, which leads to the inability to guarantee the effective development of shale oil, and to provide a method for determining shale oil viscosity.

[0005] To achieve the above objectives, the present invention provides a method for determining the viscosity of shale oil, comprising:

[0006] The intrinsic permeability of the shale sample is determined based on the gas permeability of the shale sample.

[0007] Based on the intrinsic permeability and the porosity of the shale sample, the characteristic pore throat size of the shale sample is calculated;

[0008] Based on the wettability characteristics of the shale sample, the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone were determined.

[0009] The viscosity of the aqueous phase in shale oil within shale is calculated based on the viscosity of the aqueous phase in the adsorption zone and the characteristic pore throat size. Similarly, the viscosity of the oil phase in shale oil within shale is calculated based on the viscosity of the oil phase in the adsorption zone and the characteristic pore throat size.

[0010] In this embodiment of the application, determining the intrinsic permeability of the shale sample based on the gas permeability of the shale sample includes:

[0011] Obtain the gas permeability of shale samples under multiple pressures;

[0012] The intrinsic permeability of the shale sample was determined by fitting multiple gas permeability values ​​using a target fitting formula and based on the fitting results.

[0013] In this embodiment of the application, the target fitting formula is as follows:

[0014]

[0015] Among them, K e0 Gas permeability of shale samples, in m³ 2 ;K ∞ The intrinsic permeability of the shale sample is expressed in m³. 2 b k Slip factor, in MPa; The pressure conditions corresponding to the shale sample are given in MPa.

[0016] In this embodiment of the application, the characteristic pore throat size includes the characteristic pore throat radius, and the calculation of the characteristic pore throat size of the shale sample based on the intrinsic permeability and the porosity of the shale sample includes:

[0017] The characteristic pore throat radius of the shale sample was calculated using the following formula:

[0018]

[0019] Where H is the characteristic pore throat radius of the shale sample, in meters; K ∞ The intrinsic permeability of the shale sample is expressed in m³. 2 Φ represents the porosity of the shale sample.

[0020] In this embodiment of the application, the wettability characteristics include the aqueous phase contact angle, and determining the viscosity of the aqueous phase in the adsorption region based on the wettability characteristics of the shale sample includes:

[0021] The viscosity of the aqueous phase in the adsorption region is determined based on the following formula:

[0022]

[0023] Where, μ ad1 The viscosity of the aqueous phase in the adsorption region is expressed in Pa·s; μ ∞1 θ is the bulk viscosity of water, in Pa·s; θ is the water contact angle, in degrees.

[0024] In this embodiment of the application, the wettability characteristics include the aqueous phase contact angle, and the determination of the viscosity of the oil phase in the adsorption zone based on the wettability characteristics of the shale sample includes:

[0025] The viscosity of the oil phase in the adsorption zone is determined based on the following formula:

[0026]

[0027] Where, μ ad2 The viscosity of the oil phase in the adsorption region is expressed in Pa·s; μ ∞2 τ is the bulk viscosity of the oil, expressed in Pa·s. ∞ τ is the relaxation time of the fluid in the free region, expressed in seconds. ad α is the relaxation time of the fluid in the adsorption region, in seconds; α is the proportion of the equivalent wall area in the total wall area; S is the equivalent wall area, in m². 2 σ1 is the surface tension of shale oil, in N / m; θ is the water phase contact angle, in degrees; k is the Boltzmann constant; T is the formation temperature, in K.

[0028] In this embodiment of the application, the feature throat size includes the feature throat radius;

[0029] The viscosity of the aqueous phase in shale oil is calculated using the following formula:

[0030]

[0031] Where, μ eff1 The viscosity of the aqueous phase in shale oil is expressed in Pa·s; μ ∞1 The bulk viscosity of water is expressed in Pa·s; μ ad1 y1 = H - h1, where H is the characteristic pore throat radius of the shale sample in meters, and h1 is the liquid phase adsorption thickness of the water phase in meters.

[0032] The viscosity of the oil phase in shale oil can be calculated using the following formula:

[0033]

[0034] Where, μ eff2 The viscosity of the oil phase in shale is expressed in Pa·s; μ ∞2 The viscosity of the oil is expressed in Pa·s; μ ad2 y2 = H - h2, where h2 is the viscosity of the oil phase in the adsorption zone, in Pa·s; y2 = H - h2, where h2 is the liquid phase adsorption thickness of the oil phase, in meters.

[0035] In this embodiment of the application, the method further includes:

[0036] Based on the wettability characteristics of shale samples, the velocity slip length of the water phase was determined;

[0037] The velocity slip length of the oil phase is determined based on the viscosity of the oil phase in the adsorption zone.

[0038] The apparent permeability of the aqueous phase is calculated based on the porosity, the characteristic pore throat size, and the aqueous phase velocity slip length, and the apparent permeability of the oil phase is calculated based on the porosity, the characteristic pore throat size, and the oil phase velocity slip length.

[0039] In this embodiment of the application, the wettability characteristics include the aqueous phase contact angle, and the determination of the aqueous phase velocity slip length based on the wettability characteristics of the shale sample includes:

[0040] The water phase velocity slip length is determined based on the following formula:

[0041]

[0042] Among them, l s1 θ represents the velocity slip length of the water phase, in nm; θ represents the water phase contact angle, in degrees.

[0043] The determination of the oil phase velocity slip length based on the viscosity of the oil phase in the adsorption region includes:

[0044] The oil phase velocity slip length is determined based on the following formula:

[0045]

[0046] Among them, l s2 δ is the velocity slip length of the oil phase, in meters; δ is the average distance between adjacent adsorption layers of chain alkanes in shale oil, in meters; μ ad2 The viscosity of the oil phase in the adsorption region is expressed in Pa·s; μ ∞2 This represents the bulk viscosity of the oil, expressed in Pa·s.

[0047] In this embodiment of the application, the feature throat size includes the feature throat radius;

[0048] The apparent permeability of the aqueous phase is calculated using the following formula:

[0049]

[0050] Among them, K e1 Apparent permeability of aqueous phase, in meters. 2 Φ represents the porosity of the shale sample; H represents the characteristic pore throat radius of the shale sample, in meters; l s1 This represents the velocity slip length in the water phase, in meters (m).

[0051] The apparent permeability of the oil phase is calculated based on the following formula:

[0052]

[0053] Among them, K e2 This refers to the apparent permeability of the oil phase, in meters.2 ;l s2 This represents the oil phase velocity slip length, in meters (m).

[0054] The above technical solution includes: determining the intrinsic permeability of the shale sample based on its gas permeability; calculating the characteristic pore throat size of the shale sample based on its intrinsic permeability and porosity; determining the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone based on the wettability characteristics of the shale sample; calculating the viscosity of the aqueous phase in the shale oil within the shale based on the viscosity of the aqueous phase in the adsorption zone and the characteristic pore throat size, and calculating the viscosity of the oil phase in the shale oil within the shale based on the viscosity of the oil phase in the adsorption zone and the characteristic pore throat size. The shale oil viscosity determined by the solution provided in this application takes into account the influence of nanoscale spatial confinement on viscosity. Therefore, using this shale oil viscosity as an input parameter for shale oil numerical simulation can improve the accuracy of the simulation, thereby ensuring the effective development of shale oil.

[0055] Other features and advantages of the embodiments of this application will be described in detail in the following detailed description section. Attached Figure Description

[0056] The accompanying drawings are provided to further illustrate the embodiments of this application and form part of the specification. They are used together with the following detailed description to explain the embodiments of this application, but do not constitute a limitation on the embodiments of this application. In the drawings:

[0057] Figure 1 The illustration shows a schematic flowchart of a shale oil viscosity determination method according to an embodiment of this application;

[0058] Figure 2 The illustration shows a flowchart of a method for determining apparent permeability according to an embodiment of this application;

[0059] Figure 3 The illustration shows a schematic diagram of fitting multiple gas permeability measurements according to an embodiment of this application. Detailed Implementation

[0060] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are only for illustration and explanation of the embodiments of this application and are not intended to limit the embodiments of this application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without creative effort are within the scope of protection of this application.

[0061] If the embodiments of this application involve descriptions such as "first" or "second," these descriptions are for descriptive purposes only and should not be construed as indicating or implying their relative importance or implicitly specifying the number of technical features indicated. Therefore, a feature defined with "first" or "second" may explicitly or implicitly include at least one of those features. Furthermore, the technical solutions of the various embodiments can be combined with each other, but this must be based on the ability of those skilled in the art to implement them. If the combination of technical solutions is contradictory or impossible to implement, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection claimed in this application.

[0062] As described in the background section, in the field of shale oil development, numerical simulation of shale oil is the foundation for designing oilfield exploitation schemes. Accurate input parameters are crucial for accurate and effective numerical simulations. The nanoscale pores of shale oil reservoirs constitute the primary storage space and seepage channel for shale oil. During flow through these nanopores, shale oil is affected by confinement effects, resulting in significant differences in its seepage characteristics compared to conventional oil reservoirs. However, shale oil viscosity, a key input parameter in numerical simulation, is currently mostly derived from bulk viscosity measured at the surface, without considering the nanoscale confinement effect. For example, the literature "Productivity Analysis of Shale Oil Wells Considering Start-up Pressure Gradient and Stress Sensitivity" (2017-9, Liu Lijun) established a mathematical model for shale oil seepage considering the start-up pressure gradient and stress sensitivity effects, but this model did not account for viscosity changes caused by shale adsorption within the nanoscale confined space. The literature "Study on Shale Oil Reservoir Seepage Model Considering Stress Sensitivity and Boundary Layer Effect" (2019-4, Lei Hao) analyzes the influence of stress sensitivity and boundary layer effects on shale oil seepage characteristics. However, this scheme assumes that the fluid within the adsorbed layer is immobile, equivalent to an infinite viscosity, which is inconsistent with the conclusions of nanoscale experiments and molecular dynamics studies. The literature "Productivity Model of Fractured Horizontal Wells in Shale Oil Reservoirs Considering Stratification Fractures" (2022-3, Chen Xi) establishes a three-dimensional productivity model of fractured horizontal wells in shale oil reservoirs considering stratification fractures. However, this scheme does not consider the influence of nanoscale reservoir space on reservoir fluid properties. Patent application CN109854236A uses reservoir numerical simulation software to numerically simulate shale oil flow. However, this scheme treats the adsorbed oil as an immobile solid wall, assuming an infinite viscosity of the adsorbed phase, which is inconsistent with reality and cannot accurately reflect the flow process of shale oil within nanoporous media. Therefore, the shale oil viscosity input in current shale oil numerical simulations is inaccurate, which fails to guarantee the effective development of shale oil.

[0063] To address this, one embodiment of this application provides a method for determining shale oil viscosity. The shale oil viscosity determined by this method can also be called the equivalent viscosity, which can be used as an input parameter—shale oil viscosity—when performing numerical simulations of shale oil. Figure 1 As shown, the method for determining the viscosity of shale oil may include the following steps:

[0064] Step 101: Determine the intrinsic permeability of the shale sample based on the gas permeability of the shale sample.

[0065] The shale sample may be a shale core sample.

[0066] In practical applications, shale reservoirs are dense and mainly composed of micro and nanopores. When gas flows through nanothroats, there is a nanoscale effect. Therefore, the gas permeability measured is specifically the apparent gas permeability.

[0067] Intrinsic permeability is usually only related to the pore structure and is the permeability inherent in the rock itself, and is unrelated to the test fluid.

[0068] In this embodiment of the application, determining the intrinsic permeability of the shale sample based on its gas permeability may include steps (1) and (2), as follows:

[0069] Step (1) Obtain the gas permeability of the shale sample under multiple pressures.

[0070] The plurality of pressures are all different; that is, any two of the plurality of pressures are different.

[0071] Taking any one of the multiple pressures as an example, the pressure can specifically be the average of the pressure at the inlet end of the shale sample and the pressure at the outlet end of the shale sample.

[0072] It is understandable that after obtaining the gas permeability of shale samples under multiple pressures, multiple gas permeability values ​​will be obtained, and multiple pressures will correspond one-to-one with multiple gas permeability values.

[0073] Step (2): Use the target fitting formula to fit multiple gas permeability values, and determine the intrinsic permeability of the shale sample based on the fitting results.

[0074] In practice, before fitting multiple gas permeability measurements using the target fitting formula, points corresponding to each gas permeability measurement can be plotted in a coordinate system with pressure as the abscissa and gas permeability as the ordinate. Then, the target fitting formula is used to fit these points in the coordinate system.

[0075] Furthermore, the target fitting formula can be as shown in the following formula (1):

[0076]

[0077] In formula (1), K e0Gas permeability of shale samples, in m³ 2 ;K ∞ The intrinsic permeability of the shale sample is expressed in m³. 2 b k Slip factor, in MPa; The pressure conditions corresponding to the shale samples are given in MPa. Specifically, it is the average of the inlet pressure and outlet pressure of the shale sample.

[0078] It is understandable that formula (1) can also be regarded as formula (2) below. Therefore, fitting multiple gas permeability using formula (1) is equivalent to fitting multiple gas permeability using formula (2).

[0079]

[0080] In formula (2), a = K ∞ b = K ∞ ×b k .

[0081] Therefore, after fitting the values ​​of a and b to multiple gas permeability measurements using formula (2), the intrinsic permeability K can be obtained according to the above relationship. ∞ The value and slip factor b k The value of .

[0082] Step 102: Calculate the characteristic pore throat size of the shale sample based on the intrinsic permeability and the porosity of the shale sample.

[0083] Among them, the characteristic pore throat size is the size of the pore channels that have a significant impact on the porous media of shale.

[0084] When obtaining the porosity of shale samples, methods such as helium gas and nuclear magnetic resonance can be used to measure the porosity of shale samples.

[0085] In helium-based porosity measurements, the plunger-sample helium porosity determination method is one of the more commonly used methods. Taking this method as an example, the measurement process may include: preparing a shale plunger sample using diamond wire cutting; evacuating the residual gas from the sample pores using a vacuum pump; and then saturating the sample with helium. The use of diamond wire cutting to prepare the shale plunger sample reduces the generation of artificial cracks, thereby improving the success rate of plunger sample preparation. Furthermore, during the helium saturation process, strict pressure balance conditions can be used to ensure sufficient helium saturation in the sample pores, thus obtaining the porosity measured by helium.

[0086] In practical applications, the shale nanoeffect is mainly manifested in the small size of characteristic pore throats. Therefore, in order to accurately evaluate the occurrence state and flow characteristics of shale oil within a nano-confined space, the characteristic pore throat size of shale was calculated in this embodiment. In specific implementation, the corresponding calculation formula can be obtained using a capillary bundle model.

[0087] The characteristic pore throat size can specifically include the characteristic pore throat radius, and the corresponding calculation formula is shown in formula (3) below. That is, the characteristic pore throat radius of the shale sample can be calculated based on the following formula (3):

[0088]

[0089] In formula (3), H is the characteristic pore throat radius of the shale sample, in meters; Φ is the porosity of the shale sample.

[0090] Step 103: Based on the wettability characteristics of the shale sample, determine the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone.

[0091] The wettability characteristic is an important parameter affecting fluid flow. In the embodiments of this application, the wettability characteristic may include the aqueous phase contact angle. In practical applications, the aqueous phase contact angle of shale samples can be obtained by relevant measurement methods in the prior art, which will not be elaborated here.

[0092] For aqueous fluids, when the shale wall exhibits hydrophilic characteristics, the solid-liquid interaction is strong, and the viscosity of the aqueous phase in the adsorption zone is greater than the corresponding bulk viscosity of water. When the wall exhibits hydrophobic characteristics, the solid-liquid interaction is weak, and the viscosity of the aqueous phase in the adsorption zone is less than the corresponding bulk viscosity of water. More specifically, the ratio of the viscosity of the aqueous phase in the adsorption zone to the corresponding bulk viscosity of water is a function of the contact angle of the aqueous phase.

[0093] Furthermore, in the embodiments of this application, the viscosity of the aqueous phase in the adsorption region can be determined based on the following formula (4):

[0094]

[0095] In formula (4), μ ad1 The viscosity of the aqueous phase in the adsorption region is expressed in Pa·s; μ ∞1 ρ is the bulk viscosity of water, in Pa·s; θ is the water contact angle, in degrees. Wherein, μ is the bulk viscosity of water. ∞1 It can be obtained by looking up a table.

[0096] For shale oil, the main component is chain alkanes. Therefore, in the embodiments of this application, the viscosity of the oil phase in the adsorption zone can be determined based on the following formula (5):

[0097]

[0098] In formula (5), μ ad2 The viscosity of the oil phase in the adsorption region is expressed in Pa·s; μ ∞2 τ is the bulk viscosity of the oil, expressed in Pa·s. ∞ τ is the relaxation time of the fluid in the free region, expressed in seconds. ad α is the relaxation time of the fluid in the adsorption region, in seconds; α is the proportion of the equivalent wall area in the total wall area; S is the equivalent wall area, in m². 2 σ1 represents the surface tension of shale oil, in N / m; k is the Boltzmann constant, 1.380649 × 10⁻⁶. -23 J.K. -1 T represents the formation temperature, in Kelvin (K). The corresponding bulk viscosity μ for oil is... ∞2 It can be obtained by looking up a table.

[0099] In the above formula (5), τ ∞ With τ ad The ratio τ can be used to describe the interaction strength between the solid walls of chain-like alkanes. In practical implementation, τ ∞ With τ ad The ratio can be 1.3.

[0100] In the above formula (5), the product of α and S can be calculated using the following formula (6):

[0101]

[0102] In formula (6), n is the carbon chain length of the chain alkane; L(n) is the molecular length of the chain alkane with a carbon chain length of n. Wherein, L(n) = 0.1265(n-1) + 0.46.

[0103] Step 104: Calculate the viscosity of the aqueous phase in shale oil in shale based on the viscosity of the aqueous phase in the adsorption zone and the characteristic pore throat size, and calculate the viscosity of the oil phase in shale oil in shale based on the viscosity of the oil phase in the adsorption zone and the characteristic pore throat size.

[0104] That is, in the embodiments of this application, the viscosity of shale oil includes the viscosity of the aqueous phase in shale oil within the shale and the viscosity of the oil phase in shale oil within the shale. When performing numerical simulations of shale oil, the viscosity of the aqueous phase in shale oil within the shale and the viscosity of the oil phase in shale oil within the shale can be used as input parameters.

[0105] The viscosity of the aqueous phase in shale oil within shale can be specifically referred to as the viscosity of the aqueous phase in shale within the nanopores of shale, or as the equivalent viscosity of the aqueous phase in shale within the nanopores of shale.

[0106] The viscosity of the oil phase in shale oil can be specifically referred to as the viscosity of the oil phase in the nanopores of shale oil, or the equivalent viscosity of the oil phase in the nanopores of shale oil.

[0107] In the embodiments of this application, the viscosity of the aqueous phase in shale oil can be calculated based on the following formula (7):

[0108]

[0109] In formula (7), μ eff1 y1 = H - h1, where h1 is the liquid phase adsorption thickness of the water phase in shale oil, in Pa·s;

[0110] In the embodiments of this application, the viscosity of the oil phase in shale oil can be calculated based on the following formula (8):

[0111]

[0112] In formula (8), μ eff2 y2 = H - h2, where h2 is the liquid phase adsorption thickness of the oil phase in shale, in meters.

[0113] It is understood that the shale oil viscosity determination method provided in this application includes: determining the intrinsic permeability of the shale sample based on its gas permeability; calculating the characteristic pore throat size of the shale sample based on its intrinsic permeability and porosity; determining the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone based on the wettability characteristics of the shale sample; calculating the viscosity of the aqueous phase in the shale oil based on the viscosity of the aqueous phase in the adsorption zone and the characteristic pore throat size, and calculating the viscosity of the oil phase in the shale oil based on the viscosity of the oil phase in the adsorption zone and the characteristic pore throat size. The shale oil viscosity determined by the scheme provided in this application takes into account the influence of the nanoscale spatial confinement effect on viscosity. Therefore, using this shale oil viscosity as an input parameter for shale oil numerical simulation can improve the accuracy of the simulation, thereby ensuring the effective development of shale oil.

[0114] In other words, the nanoscale pores of shale oil reservoirs are the main storage space and seepage channel for shale oil. However, due to the small pore diameter, shale oil undergoes adsorption within the nanopores, resulting in a significant difference in viscosity between the shale oil and the bulk viscosity. In shale oil numerical simulations, directly using bulk viscosity leads to substantial errors and makes it difficult to accurately describe the seepage characteristics of shale oil within the nanopores. The solution provided in this application, however, considers the influence of the nanoscale spatial confinement effect when determining shale oil viscosity. Therefore, numerical simulations based on the shale oil viscosity determined by this application's solution can improve the accuracy of the simulation.

[0115] Considering that the apparent permeability (which includes both aqueous and oil phase apparent permeability), currently one of the key input parameters for numerical simulation of shale oil, is also not accurate, the shale oil viscosity determination method provided in this application embodiment may further include:

[0116] Step 105: Determine the water phase velocity slip length based on the wettability characteristics of the shale sample.

[0117] Specifically, the velocity slip length of the water phase refers to the velocity slip length of the water phase within the shale nanochannels.

[0118] In this embodiment of the application, the water phase velocity slip length can be determined based on the following formula (9):

[0119]

[0120] In formula (9), l s1 The velocity slip length in the water phase is expressed in nm.

[0121] Step 106: Determine the oil phase velocity slip length based on the viscosity of the oil phase in the adsorption zone.

[0122] Specifically, the oil phase velocity slip length refers to the velocity slip length of the oil phase within the shale nanochannels.

[0123] In this embodiment of the application, the oil phase velocity slip length can be determined based on the following formula (10):

[0124]

[0125] In formula (10), l s2 δ represents the oil phase velocity slip length, in meters; δ is the average distance between adjacent adsorption layers of chain alkanes in shale oil, in meters. In practical implementation, δ can be taken as 0.48 × 10⁻⁶. -9 m.

[0126] For shale with strong hydrophilicity, more water phase is adsorbed and less oil phase is adsorbed within the nanochannels. The velocity slip length of the water phase on the hydrophilic wall is shorter, while the velocity slip length of the oil phase is longer.

[0127] Step 107: Calculate the apparent permeability of the aqueous phase based on the porosity, the characteristic pore throat size, and the aqueous phase velocity slip length, and calculate the apparent permeability of the oil phase based on the porosity, the characteristic pore throat size, and the oil phase velocity slip length.

[0128] That is, when performing numerical simulations of shale oil, the apparent permeability of the aqueous phase and the apparent permeability of the oil phase can be used as input parameters.

[0129] In this embodiment of the application, the apparent permeability of the aqueous phase can be calculated based on the following formula (11):

[0130]

[0131] Among them, K e1 Apparent permeability of aqueous phase, in meters. 2 .

[0132] In this embodiment of the application, the apparent permeability of the oil phase can be calculated based on the following formula (12):

[0133]

[0134] Among them, K e2 This refers to the apparent permeability of the oil phase, in meters. 2 .

[0135] It is understood that the apparent permeability determined based on the scheme provided in the embodiments of this application takes into account the influence of velocity slip. Therefore, using the apparent permeability as an input parameter for shale oil numerical simulation can further improve the accuracy of the simulation, thereby further ensuring the effective development of shale oil.

[0136] Furthermore, compared to existing methods that directly measure the apparent permeability of the aqueous and oil phases, the solution provided in the above embodiments of this application only requires obtaining the apparent permeability of the gas phase, followed by relevant calculations to obtain the apparent permeability of the aqueous and oil phases. Moreover, the time required for gas phase permeability measurement is significantly less than that required for liquid phase permeability measurement. Therefore, the solution for determining the apparent permeability of the aqueous and oil phases provided in the above embodiments of this application is less time-consuming and can greatly improve efficiency.

[0137] In summary, the solutions provided in the above embodiments of this application take into account the occurrence state and flow characteristics of shale oil in a nanoscale confined space. The nanoscale effects are represented by the viscosity and apparent permeability of shale oil determined in the above embodiments, thereby improving the accuracy of the simulation and ensuring the effective development of shale oil.

[0138] The following will illustrate the shale oil viscosity determination method provided in this application with specific examples. It should be understood that the following examples are merely specific implementation methods and do not imply any improper limitation of the solution in this application.

[0139] Example 1

[0140] Step 1: Calculate the intrinsic permeability of the shale core.

[0141] Taking a core sample from a shale oil block, the gas permeability of this shale core sample under various pressures can be obtained as follows: Figure 3 As shown at each point in the diagram.

[0142] Then, the above formula (1) is used to fit multiple gas permeability measurements, and the fitted curve can be as follows: Figure 3 As shown by the curve in the middle.

[0143] After fitting, the slip factor b can be obtained. k The intrinsic permeability K of the shale core is 0.247 MPa. ∞ It is 6.6 × 10 -18 m 2 .

[0144] Step 2: Calculate the characteristic pore throat size of the shale core.

[0145] The porosity Φ of the helium-gassed rock core is 5.37%. Based on the above formula (3), the characteristic pore throat radius of the shale core is calculated to be 3.84 × 10⁻⁶. -8 m.

[0146] Step 3: Calculate the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone.

[0147] The water phase contact angle θ of the shale core in the target area is 75°. Based on the above formula (4), the ratio of the viscosity of the water phase in the adsorption zone to the bulk viscosity of the water phase is calculated to be 1.9.

[0148] τ ∞ With τ ad The ratio is taken as 1.3, the carbon chain length n of the shale oil in the target area is 8, and the product of α and S is calculated to be 9.47 × 10 according to the above formula (6). -19 m 2 The surface tension σ1 of shale oil is 26 × 10⁻⁶. -3N / m, formation temperature T is 333K, and the ratio of the viscosity of the oil phase in the adsorption zone to the viscosity of the corresponding bulk phase is calculated to be 68.7 based on the above formula (5).

[0149] Step 4: Calculate the velocity slip length of the water phase and the velocity slip length of the oil phase.

[0150] Based on the above formula (9), the velocity slip length of the water phase is calculated to be 0.258 nm.

[0151] The average distance δ between adjacent adsorption layers of positive-configuration chain alkanes in shale oil is taken as 0.48 nm. Based on the above formula (10), the oil phase velocity slip length is calculated to be 32.5 nm.

[0152] Step 5: Calculate the apparent permeability of the aqueous phase and the apparent permeability of the oil phase.

[0153] Based on the above formula (11), the apparent permeability of the aqueous phase is calculated to be 6.61 × 10⁻⁶. -18 m 2 Based on the above formula (12), the apparent permeability of the oil phase is calculated to be 8.0 × 10⁻⁶. -18 m 2 .

[0154] Step 6: Calculate the viscosity of the aqueous phase in shale oil and the viscosity of the oil phase in shale oil.

[0155] The bulk viscosity of water is 1 mPa·s, the bulk viscosity of oil is 10 mPa·s, and the liquid phase adsorption thickness h1 of water is 0.7 × 10⁻⁶. -9 m, the corresponding liquid phase adsorption thickness h2 of the oil is 0.98 × 10 m. -9 m.

[0156] Based on the above formula (7), the viscosity of the water phase in shale oil in shale is calculated to be 1.02 mPa·s, and based on the above formula (8), the viscosity of the oil phase in shale oil in shale is calculated to be 10.67 mPa·s.

[0157] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0158] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for determining the viscosity of shale oil, characterized in that, include: The intrinsic permeability of the shale sample is determined based on the gas permeability of the shale sample. Based on the intrinsic permeability and the porosity of the shale sample, the characteristic pore throat size of the shale sample is calculated; Based on the wettability characteristics of the shale sample, the viscosity of the aqueous phase and the viscosity of the oil phase in the adsorption zone were determined. The viscosity of the aqueous phase in shale oil is calculated based on the viscosity of the aqueous phase in the adsorption zone and the characteristic pore throat size. The viscosity of the oil phase in shale oil is also calculated based on the viscosity of the oil phase in the adsorption zone and the characteristic pore throat size. The wettability characteristics include the aqueous phase contact angle; The determination of the viscosity of the aqueous phase in the adsorption zone based on the wettability characteristics of the shale sample includes: The viscosity of the aqueous phase in the adsorption region is determined based on the following formula: ； in, The viscosity of the aqueous phase in the adsorption region is expressed in Pa•s. This is the bulk viscosity of water, expressed in Pa•s; The contact angle between the aqueous phase is expressed in degrees. The determination of the viscosity of the oil phase in the adsorption zone based on the wettability characteristics of the shale sample includes: The viscosity of the oil phase in the adsorption zone is determined based on the following formula: ； in, The viscosity of the oil phase in the adsorption zone is expressed in Pa•s. This represents the bulk viscosity of the oil, expressed in Pa·s. τ ∞ The free zone fluid relaxation time is expressed in seconds. τ ad The relaxation time of the fluid in the adsorption region is expressed in seconds. α This represents the percentage of the equivalent wall area in the total wall area. S Equivalent wall area, unit is m² 2 ; The surface tension of shale oil is expressed in N / m. k Boltzmann's constant; T Formation temperature, in Kelvin (K). The characteristic throat size includes the characteristic throat radius; The viscosity of the aqueous phase in shale oil is calculated using the following formula: ； in, The viscosity of the aqueous phase in shale oil is expressed in Pa•s. y 1= Hh 1, H denoted as the characteristic pore throat radius of the shale sample, in meters. h 1 represents the liquid phase adsorption thickness corresponding to water, in meters (m). The viscosity of the oil phase in shale oil can be calculated using the following formula: ； in, The viscosity of the oil phase in shale is expressed in Pa•s. y 2= Hh 2, h 2 represents the liquid phase adsorption thickness corresponding to the oil, in meters (m).

2. The method for determining shale oil viscosity according to claim 1, characterized in that, The determination of the intrinsic permeability of the shale sample based on gas permeability measurement includes: Obtain the gas permeability of shale samples under multiple pressures; The intrinsic permeability of the shale sample was determined by fitting multiple gas permeability values ​​using a target fitting formula and based on the fitting results.

3. The method for determining shale oil viscosity according to claim 2, characterized in that, The target fitting formula is as follows: ； in, Gas permeability of shale samples, in m³ 2 ; The intrinsic permeability of the shale sample is expressed in m³. 2 ; Slip factor, in MPa; The pressure conditions corresponding to the shale sample are given in MPa.

4. The method for determining shale oil viscosity according to claim 1, characterized in that, The step of calculating the characteristic pore throat size of the shale sample based on the intrinsic permeability and the porosity of the shale sample includes: The characteristic pore throat radius of the shale sample was calculated using the following formula: ； in, The intrinsic permeability of the shale sample is expressed in m³. 2 ; The porosity of the shale sample.

5. The method for determining shale oil viscosity according to claim 1, characterized in that, The method further includes: Based on the wettability characteristics of shale samples, the velocity slip length of the water phase was determined; The velocity slip length of the oil phase is determined based on the viscosity of the oil phase in the adsorption zone. The apparent permeability of the aqueous phase is calculated based on the porosity, the characteristic pore throat size, and the aqueous phase velocity slip length, and the apparent permeability of the oil phase is calculated based on the porosity, the characteristic pore throat size, and the oil phase velocity slip length.

6. The method for determining shale oil viscosity according to claim 5, characterized in that, The determination of the water phase velocity slip length based on the wettability characteristics of shale samples includes: The water phase velocity slip length is determined based on the following formula: ； in, This represents the velocity slip length in the water phase, in meters (m). The determination of the oil phase velocity slip length based on the viscosity of the oil phase in the adsorption region includes: The oil phase velocity slip length is determined based on the following formula: ； in, This represents the oil phase velocity slip length, in meters (m). This represents the average distance between adjacent adsorption layers of chain alkanes in shale oil, expressed in meters (m).

7. The method for determining shale oil viscosity according to claim 5, characterized in that, The apparent permeability of the aqueous phase is calculated using the following formula: ； in, Apparent permeability of aqueous phase, in meters. 2 ; Porosity of the shale sample; This represents the velocity slip length in the water phase, in meters (m). The apparent permeability of the oil phase is calculated based on the following formula: ； in, This refers to the apparent permeability of the oil phase, in meters. 2 ; This represents the oil phase velocity slip length, in meters (m).

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