Calculation method of fracturing fluid imbibition depth during shale oil reservoir horizontal well fracturing-soaking period

Abstract

The invention discloses a method for calculating the imbibition depth of fracturing fluid in the shale oil reservoir horizontal well fracturing-soaking period, belongs to the field of petroleum and natural gas development, and aims at solving the problem that the imbibition depth of the fracturing fluid is difficult to accurately predict in the shale oil reservoir fracturing process. Combining the Darcy law and the basic principle of oil and gas reservoir engineering, comprehensively considering the combined action of capillary force and viscous resistance on the seepage process, and establishing an expression of the imbibition volume of the fracturing fluid by defining the seepage velocity; the relation between the change of the water saturation in the matrix before and after imbibition and the imbibition volume is introduced, and a calculation model of the shale oil reservoir fracturing fluid imbibition depth is constructed according to the principle that the imbibition volume is equal, so that the accuracy of imbibition depth prediction is remarkably improved, and the method has good practicability and expandability and is suitable for popularization and application. Scientific basis is provided for evaluation of the imbibition effect of the fracturing fluid, theoretical support is provided for optimization design of a fracturing scheme, and the development efficiency of oil and gas reservoirs is effectively improved.

Description

Technical Field

[0001] The invention belongs to the field of oil and natural gas development, and in particular relates to a method for calculating the imbibition depth of fracturing fluid during the fracturing-well shut-in period of a horizontal well in a shale oil reservoir. Background Art

[0002] For low-porosity and low-permeability shale reservoirs, horizontal wells combined with multi-stage fracturing technology are effective means to improve crude oil recovery. Taking well-insertion measures after fracturing can achieve better production-increasing effects. Through the fracturing transformation method, a larger area of ​​crack spread can be obtained, increasing the seepage space of oil and gas, which is conducive to the invasion of fracturing fluid into matrix pores. During the fracturing and insufflation period, the invasion depth of the fracturing fluid directly reflects the degree of penetration of the fracturing fluid in the rock pores. Studying the imbibition depth of the fracturing fluid has important theoretical and practical significance for evaluating the imbibition effect of the fracturing fluid, the dynamic change law of fracturing imbibition, and planning fracturing and mining plans in advance.

[0003] At present, the research on imbibition is mainly divided into indoor experimental research and theoretical research. In terms of theoretical research, Lucas and Washburn assumed that the imbibition fluid is an incompressible Newtonian fluid, and the imbibition channel is assumed to be a uniform circular capillary tube. Based on fluid dynamics and seepage theory, the expression of the imbibition velocity is obtained, and the theoretical model of the imbibition distance is obtained by integrating the velocity. (Edward W. Washburn. The Dynamics of Capillary Flow [J]. Physical Review, 1921, Vol. 17 (3): 273) Based on the LW model, Benavente considered the complexity of the pore microstructure, introduced the correction of tortuosity and pore shape factor, and combined Poiseuille's law to calculate the imbibition depth. (David Benavente; Peter Lock; M García Del Cura; Salvador Predicting the Capillary Imbibition of Porous Rocks from Microstructure[J]. Transport in Porous Media, 2002, Vol. 49(1): 59-76); Wang Fei, Yang Bin et al., considering the influence of confinement effect caused by changes in osmotic pressure and viscosity, derived the self-imbibition momentum equation based on the momentum theorem to obtain the self-imbibition depth. (Wang Fei, Pan Ziqing. Numerical simulation of fracturing fluid flowback in shale reservoirs driven by chemical potential difference[J]. Petroleum Exploration and Development, 2016, 43(06): 971-977.). Yang Jian et al., considering the influence of colloidal polymer residue and capillary force in fracturing fluid, derived the invasion rate of fracturing fluid through SUPALAK model and Darcy's law, and obtained the imbibition depth model using seepage theory and mass conservation equation. (Yang Jian, Yang Bin, Wang Liang, et al. Study on the invasion depth of fracturing fluid imbibition in matrix pores of shale oil reservoirs in Da'anzhai section of central Sichuan [J]. Petroleum Geology and Recovery, 2023, 30(05): 84-91.); Wu Zhongxiong et al., based on the seepage theory, established the fluid motion equation considering the starting pressure gradient, thus obtaining the reverse imbibition control equation, combined with the capillary force curve, and used the multivariate nonlinear regression method to calculate the maximum imbibition distance of reverse imbibition in shale oil reservoirs. (Wu Zhongwei, Qin Lei, Cui Chuanzhi, et al. Calculation method of maximum imbibition distance of reverse imbibition in shale oil reservoirs [J]. Special Oil and Gas Reservoirs, 2024, 31(04): 103-108.). In terms of experiments, Ren Kai et al., considering the influence of shale bedding, used the volumetric method to calculate the imbibition amount through spontaneous imbibition experiments, processed the data, and studied the changing law of imbibition distance. (Ren Kai, Ge Hongkui, Yang Liu, et al. Shale self-imbibition experiment and its application in flowback analysis [J]. Science Technology and Engineering, 2015, 15(30):) Yang Zhengming, Sun Daokun, et al., used a high-pressure large-model physical simulation system and nuclear magnetic resonance technology to establish a physical simulation experimental method for core imbibition of different scales. The imbibition distance in the imbibition process was calculated by the change law of the model pressure field before and after the imbibition experiment and the change law of the T2 spectrum. (Yang Zhengming, Liu Xuewei, Li Haibo, et al. Analysis of factors affecting imbibition in tight reservoirs and evaluation of imbibition effects [J]. Petroleum Exploration and Development, 2019, 46(04): 739-745.).

[0004] In the above research, the established theoretical model only considers capillary self-imbibition, and the calculation process has problems such as long time consumption and inaccurate results. At the same time, the use of linear regression to solve the formula will also be interfered by factors such as excessive empiricism and difficulty in determining the number of samples. In terms of experiments, although it is possible to obtain imbibition data from fracturing fluid core samples, the experimental process is usually affected by the precision limitations of the experimental equipment and its own limitations, and the experimental conditions are difficult to accurately simulate the actual formation environment. Therefore, the present invention is based on the fact that artificial fractures are related to water content, according to the imbibition principle of fracturing fluid, starting from Darcy's law, and using oil and gas reservoir methods to establish a method for calculating the imbibition depth of fracturing fluid during fracturing-well soaking in horizontal wells in shale reservoirs. Summary of the invention

[0005] Aiming at the problem that it is difficult to accurately predict the imbibition depth of fracturing fluid during the fracturing process of shale oil reservoirs, the present invention proposes a method for calculating the imbibition depth of fracturing fluid during the fracturing-well shut-in of horizontal wells in shale oil reservoirs; the method starts from the imbibition principle of fracturing fluid, combines Darcy's law and the basic principles of oil and gas reservoir engineering, comprehensively considers the joint effect of capillary force and viscous resistance on the seepage process, and establishes an expression for the imbibition volume of fracturing fluid through the definition of seepage velocity; and introduces the relationship between the change of water saturation in the matrix before and after imbibition and the imbibition volume, and constructs a calculation model for the imbibition depth of fracturing fluid in shale oil reservoirs based on the principle of equal imbibition volume. The present invention can not only significantly improve the accuracy of imbibition depth prediction, but also has good practicality and scalability, providing reliable technical support and broad application prospects for shale oil reservoir fracturing engineering.

[0006] In order to achieve the above technical objectives, the present invention adopts the following technical scheme, including the following steps:

[0007] Step S1: Obtain reservoir physical parameters and fluid property parameters, including porosity φ, initial water saturation S mwo , bound water saturation S mwc , matrix permeability k, wetting angle θ of the wetting phase fluid, interfacial tension σ of the two phases, capillary radius r; pore tortuosity τ, fluid viscosity μ;

[0008] Step S2: In shale reservoirs, consider the original water saturation of the bedrock as S mwo , bedrock bound water saturation is S mwc During fracturing, due to the imbibition effect, the water content within the imbibition depth range d of the bedrock surface in contact with the artificial fracture reaches the bound water saturation of the bedrock. Based on the relationship between the water content of the artificial fracture and fracturing (the S mwc >S mwo ), the imbibition volume can be expressed as:

[0009] V ms =Adφ(S mwc -Smwo ) (1)

[0010] Where: A is the imbibition area, cm 2 ; S mwc is bound water saturation, %; S mwo is the initial water saturation, %; d is the imbibition depth, cm; φ is the porosity, %;

[0011] Step S3: Shale reservoirs are different from conventional reservoirs and have the characteristics of low porosity and low permeability. The fracturing technology is used to transform the reservoir to enhance the high permeability volume space for fluid flow. The imbibition area of ​​the fracturing fluid invading the formation due to spontaneous imbibition is related to the injection volume of the fracturing fluid and the pore throat structure of the reservoir. Combined with the actual reservoir tortuosity and fracturing construction parameters, the imbibition volume of the fracturing fluid can be further expressed as:

[0012]

[0013] Where: k is permeability, mD; r is capillary radius, cm; τ is pore tortuosity; V ms is the imbibition volume of the fracturing fluid, cm 3 ;

[0014] Step S4: According to the imbibition characteristics of the fracturing fluid in the porous medium, the capillary force and viscous resistance act together when the fracturing fluid flows in the pores. When the fracturing fluid flows in the pores, the capillary force acts as a driving force to push the fracturing fluid into the formation, and the viscous force of the pore wall acts as a resistance to inhibit the flow of the fracturing fluid. According to Darcy's law, the seepage velocity is expressed as:

[0015]

[0016] Where: v is the seepage velocity, cm / s; μ is the fluid viscosity, mPa·s; P c is the capillary force, MPa; F v is the viscous resistance, MPa;

[0017] Step S5: After the formation is fractured, the fracturing fluid enters the matrix pores under the combined action of capillary force and viscous resistance. According to Darcy's formula, the seepage velocity is further derived as:

[0018]

[0019] Where: σ is the interfacial tension between the two phases, N / cm; θ is the wetting angle of the wetting phase fluid, ;

[0020] Step S6: Based on the definition of seepage velocity, when the fracturing fluid flows in the matrix pores, since the pores constituting the porous medium are curved and irregular, the imbibition velocity of the fracturing fluid in the pores is related to the pore shape and the imbibition surface. The seepage velocity can be expressed as:

[0021]

[0022] Where: q is the flow rate of fracturing fluid through the seepage surface, cm 3 / s;

[0023] Step S7: The imbibition volume is the volume of the fracturing fluid injected at a certain flow rate accumulated over a period of time. Based on the definition of the imbibition volume, the imbibition volume can be expressed as:

[0024]

[0025] Where: t is time, s; V ms is the imbibition volume of the fracturing fluid, cm 3 ;

[0026] Step S8: During the fracturing period, the total volume of the imbibition surface through which the fracturing fluid passes is related to the property parameters of the fracturing fluid, the capillary force, and the viscous resistance. The integral of the imbibition volume is derived to obtain:

[0027]

[0028] Step S9: During the fracturing period, the fracturing fluid enters the matrix pores due to the imbibition effect under the action of capillary force and viscous resistance. The penetration depth of the fracturing fluid in the pores is related to the change of reservoir pore size, fluid properties and fracturing flowback conditions. By comprehensively considering the effects of fluid properties and tortuosity on the imbibition depth, and combining actual fracturing construction, seepage theory and Darcy's law, the expression of the imbibition depth during the fracturing period can be derived as follows:

[0029]

[0030] Further, the process of step S3 is as follows:

[0031] Step S31: Since the flow of the fracturing fluid in the porous medium does not proceed in a straight line, but flows forward in a circuitous manner, in order to correct the capillary bundle model, the Gozeny-Kalman method introduces the tortuosity or tortuosity of the pores. The porosity can be expressed as:

[0032]

[0033] Step S32: Considering the effect of tortuosity on fracturing fluid imbibition, formula (9) is substituted into formula (1) to obtain formula (2) for fracturing fluid imbibition volume related to water content:

[0034]

[0035] Further, the process of step S5 is as follows:

[0036] Step S51: When the fluid flows in the pore channel, capillary force is generated due to the existence of interfacial tension. The capillary force on the fluid can be described by the classic Young-Laplace equation:

[0037]

[0038] Step S52: During fracturing, the interaction force between fluid molecules causes relative displacement of fluid molecules, generating viscous resistance, which is proportional to the viscosity and velocity of the fluid; wherein, v is the fluid seepage velocity, v=dd / dt, d is the fluid invasion depth, and μ is the fluid viscosity; the imbibition process is an incompressible Newtonian fluid flowing at a low speed in a circular tube with a small radius, and the flow resistance conforms to Poiseuille's law, therefore, the viscous resistance can be expressed by the following formula:

[0039] F v =8dπμv (11)

[0040] Step S53: Substitute formula (10) and formula (11) into formula (3) to obtain:

[0041]

[0042] Therefore, the seepage velocity can be further expressed as:

[0043]

[0044] Further, the process of step S6 is as follows:

[0045] Step S61: Based on the definition of seepage velocity, the seepage velocity is the ratio of volume flow rate to the effective imbibition surface of the fracturing fluid, and the seepage velocity can be expressed as:

[0046]

[0047] Step S62: Combining formula (9) and formula (13), we can get formula (5):

[0048]

[0049] Further, the process of step S8 is as follows:

[0050] Step S81: Based on the equal fluid seepage velocity, formula (4) and formula (5) are combined to obtain:

[0051]

[0052] Step S82: By combining Darcy's law and the definition of seepage velocity, formula (4) and formula (5) are combined to further calculate the flow rate. The flow rate q can be expressed as:

[0053]

[0054] Step S83: Substituting formula (15) into formula (6), the volume flow rate per unit time of the imbibition depth can be obtained. The imbibition volume is expressed as:

[0055]

[0056] Step S84: After integral calculation of time, the relationship of seepage volume is obtained as follows:

[0057]

[0058] Further, the process of step S9 is as follows:

[0059] Step S91: By combining formula (2) and formula (6), the imbibition volume can be further expressed as:

[0060]

[0061] Step S92: Based on the fact that the imbibition volume is related to water saturation, capillary force, viscous resistance and property parameters of the fracturing fluid, combined with the seepage theory method, the imbibition depth of the fracturing fluid is derived:

[0062]

[0063] As a further description of the above technical solution:

[0064] Compared with the prior art, the present invention has the following beneficial effects:

[0065] The present invention proposes a method for calculating the imbibition depth of fracturing fluid during the fracturing-well soaking period of horizontal wells in shale oil reservoirs. The method is based on the principle of fracturing fluid imbibition, Darcy's law and the principle of oil and gas reservoir engineering, comprehensively considers the influence of capillary force and viscous resistance, and establishes an expression for imbibition volume through the definition of seepage velocity; and introduces the relationship between the change of water saturation in the matrix before and after imbibition and the imbibition volume, and establishes a calculation model for imbibition depth based on the principle of "equal imbibition volume". Compared with the prior art, the present invention overcomes the problems of complex calculation, strong linear regression empiricism and limited sample number of the existing theoretical model; and avoids the problems of limited experimental conditions, inaccurate measurement of imbibition distance and long experimental time. The present invention can more accurately predict the imbibition depth of fracturing fluid in cracks and matrix, which not only provides a scientific basis for the evaluation of the imbibition effect of fracturing fluid, but also provides theoretical support for the optimization design of fracturing schemes, and can effectively improve the development efficiency of oil and gas reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0066] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0067] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, for ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative labor.

[0068] Figure 1 A flow chart of a method for calculating the imbibition depth of fracturing fluid during the fracturing-well shut-in period of a horizontal well in a shale oil reservoir;

[0069] Figure 2 is a fracturing invasion depth curve with different well shut-in times according to one embodiment of the present invention;

[0070] Figure 3 is a curve showing the variation of the imbibition depth with time at different permeabilities according to one embodiment of the present invention;

[0071] Figure 4 is a curve showing the variation of the imbibition depth with time at different pore radii according to an embodiment of the present invention;

[0072] Figure 5 is a curve showing a change of the imbibition depth with time at different water saturations according to an embodiment of the present invention;

[0073] Figure 6 1 is a curve showing the change of the imbibition depth with time at different wetting angles according to an embodiment of the present invention. DETAILED DESCRIPTION

[0074] The present invention is further described below with reference to the accompanying drawings and examples, so that those skilled in the art can understand the present invention. However, it should be clear that the present invention is not limited to the scope of the specific embodiments, and for those skilled in the art, as long as various changes are within the spirit and scope of the present invention defined and determined by the attached claims, they are all protected.

[0075] Implementation Examples

[0076] A method for calculating the imbibition depth of fracturing fluid after fracturing-well soaking measures. The calculation process is shown in Figure 1 , including the following steps in sequence:

[0077] Step S1. Take a shale oil reservoir as an example to perform model verification analysis and obtain fluid property parameters and fracturing parameters (values ​​are shown in Table 1):

[0078] Table 1 Fluid property parameters and reservoir parameters

[0079] parameter Value parameter Value Permeability (mD) 0.001 Immune water saturation (%) 43 Porosity(%) 4 Initial water saturation (%) 10 Tortuosity (τ) 5 Pore ​​radius (cm) <![CDATA[8×10 -7 ]]> Viscosity (mPa·s) 1.5 Wetting contact angle (°) 78 Surface tension (N / cm) <![CDATA[8×10 -5 ]]>

[0080] S2. In shale reservoirs, the original water saturation of the bedrock is considered to be S mwo , bedrock bound water saturation is S mwc During fracturing, due to the imbibition effect, the water content within the imbibition depth range d of the bedrock surface in contact with the artificial fracture reaches the bound water saturation of the bedrock. Based on the relationship between the water content of the artificial fracture and fracturing (the S mwc >S mwo ), the imbibition volume can be expressed as:

[0081] V ms =Adφ(S mwc -S mwo ) (1)

[0082] S3. Shale reservoirs are different from conventional reservoirs and have the characteristics of low porosity and low permeability. The fracturing technology is used to transform the reservoir to increase the high permeability volume space for fluid flow. The contact area of ​​the fracturing fluid invading the formation due to spontaneous imbibition is related to the injection volume of the fracturing fluid and the pore throat structure of the reservoir. Combined with the actual reservoir tortuosity and fracturing construction parameters, the imbibition volume can be expressed as:

[0083] S31. Since the flow of fracturing fluid in porous media does not proceed in a straight line, but flows forward in a circuitous manner, in order to correct the capillary bundle model, the Gozeny-Kalman method introduces the tortuosity or tortuosity of the pores. The porosity can be expressed as:

[0084]

[0085] S32. Considering the effect of tortuosity on the imbibition of fracturing fluid, the imbibition volume of fracturing fluid can be obtained by combining the above formula:

[0086]

[0087] S4. According to the imbibition characteristics of the fracturing fluid in porous media, the fracturing fluid is subject to the combined effects of capillary force and viscous resistance when flowing in the pores. When the fracturing fluid flows in the pores, the capillary force acts as a driving force to push the fracturing fluid into the formation, and the viscous force of the pore wall acts as resistance to inhibit the flow of the fracturing fluid. The seepage velocity can be expressed by Darcy's law as:

[0088]

[0089] S5: After the formation is fractured, the fracturing fluid enters the matrix pores under the combined action of capillary force and viscous resistance. According to Darcy's formula, the seepage velocity is further derived as:

[0090] S51. When a fluid flows in a pore channel, capillary force is generated due to the presence of interfacial tension. The capillary force on the fluid can be described by the classic Young-Laplace equation:

[0091]

[0092] S52. During fracturing, the fracturing fluid flows in the capillary tube. The interaction force between the fluid molecules causes the fluid molecules to move relative to each other, generating viscous resistance. The viscous resistance is proportional to the viscosity and velocity of the fluid. The viscous resistance can be expressed by the following formula:

[0093] F v =8dπμv (11)

[0094] S53. Substituting formula (10) and formula (11) into formula (3), we can obtain:

[0095]

[0096] Therefore, the seepage velocity can be further expressed as:

[0097]

[0098] S6. Based on the definition of seepage velocity, when the fracturing fluid flows in the matrix pores, since the pores that make up the porous medium are curved and irregular, the imbibition velocity of the fracturing fluid in the pores is related to the pore shape and the imbibition surface. The seepage velocity can be expressed as:

[0099] S61. Based on the definition of seepage velocity, which is the ratio of flow rate to effective imbibition surface of fracturing fluid, the seepage velocity can be expressed as:

[0100]

[0101] S62. Combining formula (9) and formula (13), we can get formula (5):

[0102]

[0103] S7. The imbibition volume is the volume of the fracturing fluid injected at a certain flow rate over a period of time. Based on the definition of imbibition volume, the imbibition volume can be expressed as:

[0104]

[0105] S8. During the fracturing period, the total volume of the imbibition surface through which the fracturing fluid passes is related to the properties of the fracturing fluid, capillary force, and viscous resistance. The imbibition volume is derived as:

[0106] S81. According to the equal fluid seepage velocity, formula (4) and formula (5) can be combined to obtain:

[0107]

[0108] S82. By combining Darcy's law and the definition of seepage velocity, formula (4) and formula (5) are combined to further calculate the flow rate. The flow rate q can be expressed as:

[0109]

[0110] S83. Substituting formula (15) into formula (6), the volume flow rate during the imbibition depth pressure stewing period can be obtained, and the imbibition volume is expressed as:

[0111]

[0112] S84. After integrating the time, the relationship between the seepage volume and the flow volume is:

[0113]

[0114] S9. During the fracturing period, the fracturing fluid enters the matrix pores due to the action of capillary force and viscous resistance. The penetration depth of the fracturing fluid in the pores is related to the change in reservoir pore size, fluid properties and reservoir water content. By comprehensively considering the effects of fluid properties and tortuosity on the imbibition depth, and combining actual fracturing construction, seepage theory and Darcy's law, the expression of the imbibition depth during fracturing can be derived as follows:

[0115] S91. Combining formula (2) and formula (7), the imbibition volume can be further expressed as:

[0116]

[0117] S92. Based on the relationship between imbibition volume and water saturation, capillary force, viscous resistance and property parameters of fracturing fluid, combined with the seepage theory method, the imbibition depth of fracturing fluid is derived:

[0118]

[0119] S93. In the pore radius of 8×10 -7 cm, and the soaking time is 30 days. The reservoir parameters are shown in Table 1. The reservoir permeability is 0.001 mD, the irreducible water saturation is 43%, the original water saturation is 10%, and the viscosity μ is 1.5×10 -3 N·s / cm 2 , the porosity is 4%, and the imbibition depth is:

[0120]

[0121] S94. Reservoir parameters are shown in Table 1. Under the condition that other parameters remain unchanged, the imbibition depths are calculated when the well is shut down for 10 days (864000 s), 30 days (2592000 s), 50 days (4320000 s), 70 days (6048000 s) and 90 days (7776000 s). It can be seen that the imbibition depths under different well shut down times are Figure 2 , Table 2.

[0122] Table 2 Changes of imbibition depth with different soaking time

[0123]

[0124] S95. Reservoir parameters are shown in Table 1. Other parameters remain unchanged. The imbibition depths at different permeabilities of 0.0001mD, 0.0005mD, 0.001mD and 0.0015mD are calculated when the soaking time is 10d (864000s), 30d (2592000s), 50d (4320000s), 70d (6048000s) and 90d (7776000s). The changes in the imbibition depth under different permeabilities can be seen. Figure 3 , Table 3.

[0125] Table 3 Changes of imbibition depth over time under different permeability conditions

[0126]

[0127] S96. Reservoir parameters are shown in Table 1. When other parameters remain unchanged, the imbibition depths at soak times of 10 d (864000 s), 30 d (2592000 s), 50 d (4320000 s), 70 d (6048000 s) and 90 d (7776000 s) under different pore radii of 8 nm, 12 nm, 16 nm and 20 nm are calculated as shown in Table 4. Figure 4 shown.

[0128] Table 4 Changes of imbibition depth over time under different pore radius conditions

[0129]

[0130] S97. Reservoir parameters are shown in Table 1. When other parameters remain unchanged, the imbibition depths at different water saturation conditions with soaking times of 10 days (864,000 s), 30 days (2,592,000 s), 50 days (4,320,000 s), 70 days (6,048,000 s) and 90 days (7,776,000 s) are calculated as shown in Tables 5, Figure 5 shown.

[0131] Table 5 Changes of imbibition depth over time under different water saturation conditions

[0132]

[0133] S98. Reservoir parameters are shown in Table 1. Under the condition that other parameters remain unchanged, as shown in Table 6, Figure 6 As shown, the imbibition depth under different wetting angle conditions when the soaking time is 10d (864000s), 30d (2592000s), 50d (4320000s), 70d (6048000s) and 90d (7776000s) respectively.

[0134] Table 6 Changes of imbibition depth over time under different wetting angles

[0135]

[0136] The above description is not intended to be a formal limitation on the present invention. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention are still within the scope of the technical solution of the present invention.

Claims

1. A method for calculating the imbibition depth of fracturing fluid during fracturing and well shut-in of a horizontal well in a shale oil reservoir, characterized in that: The following steps are involved: Step S1: Obtain reservoir physical property parameters and fluid property parameters; Including porosity φ, initial water saturation S mwo , bound water saturation S mwc , matrix permeability k, wetting angle θ of the wetting phase fluid, interfacial tension σ of the two phases, capillary radius r, pore tortuosity τ, and fluid viscosity μ; Step S2: Consider the original water saturation of the bedrock as S mwo , bedrock bound water saturation is S mwc During fracturing, due to the imbibition effect, the water content within the imbibition depth range d of the bedrock surface in contact with the artificial fracture reaches the bound water saturation of the bedrock. Based on the relationship between the water content of the artificial fracture and fracturing (the S mwc >S mwo ), the imbibition volume can be expressed as: V ms =Adφ(S mwc -S mwo ) (1) Where: A is the imbibition area, cm 2 ; S mwc is bound water saturation, %; S mwo is the initial water saturation, %; d is the imbibition depth, cm; φ is the porosity, %; Step S3: The reservoir is transformed by using the fracturing technology to increase the high permeability volume space for fluid flow. The imbibition area of ​​the fracturing fluid invading the formation due to spontaneous imbibition is related to the injection volume of the fracturing fluid and the pore throat structure of the reservoir. Combined with the actual reservoir tortuosity and fracturing construction parameters, the imbibition volume of the fracturing fluid can be further expressed as: Where: k is permeability, mD; r is capillary radius, cm; τ is pore tortuosity; V ms is the imbibition volume of the fracturing fluid, cm 3 ; Step S4: When the fracturing fluid flows in the pores, it is subjected to the combined effects of capillary force and viscous resistance. At this time, the capillary force acts as a driving force to push the fracturing fluid into the formation, and the viscous force of the pore wall acts as a resistance to inhibit the flow of the fracturing fluid. According to Darcy's law, the seepage velocity is expressed as: Where: v is the seepage velocity, cm / s; μ is the fluid viscosity, mPa·s; P c is the capillary force, MPa; F v is the viscous resistance, MPa; Step S5: After the formation is fractured, the fracturing fluid enters the matrix pores under the combined action of capillary force and viscous resistance. According to Darcy's formula, the seepage velocity is further derived as: Where: σ is the interfacial tension between the two phases, N / cm; θ is the wetting angle of the wetting phase fluid, Step S6: Based on the definition of seepage velocity, when the fracturing fluid flows in the matrix pores, since the pores constituting the porous medium are curved and irregular, the imbibition velocity of the fracturing fluid in the pores is related to the pore shape and the imbibition surface. The seepage velocity can be expressed as: Where: q is the flow rate of fracturing fluid through the seepage surface, cm 3 / s; Step S7: The imbibition volume is the volume of the fracturing fluid injected at a certain flow rate accumulated over a period of time. Based on the definition of the imbibition volume, the imbibition volume can be expressed as: Where: t is time, s; V ms is the imbibition volume of the fracturing fluid, cm 3 ; Step S8: During the fracturing period, the total volume of the imbibition surface through which the fracturing fluid passes is related to the property parameters of the fracturing fluid, the capillary force, and the viscous resistance. The integral of the imbibition volume is derived to obtain: Step S9: By comprehensively considering the effects of fluid properties and tortuosity on imbibition depth, and combining actual fracturing operation, seepage theory and Darcy's law, the expression of imbibition depth during fracturing can be derived as follows:

2. The method for calculating the imbibition depth of the fracturing fluid during the fracturing and well shut-in period of a horizontal well in a shale oil reservoir according to claim 1, characterized in that: The specific process of step S3 is as follows: Step S31: Since the flow of the fracturing fluid in the porous medium does not proceed in a straight line, but flows forward in a circuitous manner, in order to correct the capillary bundle model, the Gozeny-Kalman method introduces the tortuosity or tortuosity of the pores. The porosity can be expressed as: Step S32: Considering the effect of tortuosity on fracturing fluid imbibition, formula (9) is substituted into formula (1) to obtain formula (2) for fracturing fluid imbibition volume related to water content:

3. The method for calculating the imbibition depth of the fracturing fluid during the fracturing and well shut-in period of a horizontal well in a shale oil reservoir according to claim 1, characterized in that: The specific process of step S5 is as follows: Step S51: When the fluid flows in the pore channel, capillary force is generated due to the existence of interfacial tension. The capillary force on the fluid can be described by the classic Young-Laplace equation: Step S52: During fracturing, the interaction force between fluid molecules causes relative displacement of fluid molecules, generating viscous resistance. The viscous resistance is proportional to the viscosity and velocity of the fluid, where v is the fluid seepage velocity, v=dd / dt, d is the fluid invasion depth, and μ is the fluid viscosity. The imbibition process is an incompressible Newtonian fluid flowing at a low speed in a circular tube with a small radius, and the flow resistance conforms to Poiseuille's law. Therefore, the viscous resistance can be expressed by the following formula: F v =8dπμv (11) Step S53: Substituting formula (10) and formula (11) into formula (3) yields: Therefore, the seepage velocity can be further expressed as:

4. The method for calculating the imbibition depth of the fracturing fluid during the fracturing and well shut-in period of a horizontal well in a shale oil reservoir according to claim 1, characterized in that: The specific process of step S6 is as follows: Step S61: Based on the definition of seepage velocity, the seepage velocity is the ratio of volume flow rate to the effective imbibition surface of the fracturing fluid, and the seepage velocity can be expressed as: Step S62: Combining formula (9) and formula (13), we can get formula (5):

5. The method for calculating the imbibition depth of fracturing fluid during fracturing and well shut-in of a horizontal well in a shale oil reservoir according to claim 1, characterized in that: The specific process of step S8 is as follows: Step S81: Based on the equal fluid seepage velocity, formula (4) and formula (5) are combined to obtain: Step S82: By combining Darcy's law and the definition of seepage velocity, formula (4) and formula (5) are combined to further calculate the flow rate. The flow rate q can be expressed as: Step S83: Substituting formula (15) into formula (6), the volume flow rate per unit time of the imbibition depth can be obtained. The imbibition volume is expressed as: Step S84: After integral calculation of time, the relationship of seepage volume is obtained as follows:

6. The method for calculating the imbibition depth of fracturing fluid during fracturing and well shut-in of a horizontal well in a shale oil reservoir according to claim 1, characterized in that: The specific process of step S9 is as follows: Step S91: By combining formula (2) and formula (6), the imbibition volume can be further expressed as: Step S92: Based on the fact that the imbibition volume is related to water saturation, capillary force, viscous resistance and property parameters of the fracturing fluid, combined with the seepage theory method, the imbibition depth of the fracturing fluid is derived:

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