Hydrophilic unconventional oil horizontal well volume fracturing soaking time design method

Abstract

The present application relates to the technical field of unconventional reservoir development and drainage, and provides a hydrophilic unconventional oil horizontal well volume fracturing post-soaking time design method, which comprises the following steps: S100, evaluating reservoir wettability and determining that the reservoir is a hydrophilic reservoir; S200, establishing a horizontal well segmented cluster fracturing post-reservoir fluid seepage basic physical model and determining basic conditions of the soaking time design method; S300, determining a soaking time calculation formula based on Darcy's law and seepage velocity; S400, collecting data values of parameters of the soaking time calculation formula; and S500, substituting the data values into the soaking time calculation formula to calculate equivalent reasonable soaking time. The method can achieve the technical effect that unconventional reservoir volume fracturing horizontal wells can be opened and oil can be seen.

Description

Technical Field

[0001] This invention relates to the field of unconventional reservoir development and drainage technology, and more specifically to a method for designing the well-sinking time after volumetric fracturing of a hydrophilic unconventional horizontal well. Background Technology

[0002] Domestic and international oil companies have been focusing their efforts on developing unconventional oil reservoirs such as tight oil and shale oil. Many of the reservoirs already developed and under development are hydrophilic, meaning that the reservoir rock surface preferentially adsorbs water molecules but not oil molecules. The development of these reservoirs primarily employs a combination of techniques: horizontal wells, volumetric fracturing, and well-cooling. Well-cooling effectively utilizes the high-pressure injection energy from fracturing to enhance oil-water exchange in hydrophilic reservoirs. Field practice shows that short well-cooling times result in insufficient oil-water exchange within the reservoir, leading to prolonged oil breakthrough times and persistently high water cuts in the wells. Conversely, excessively long well-cooling times result in the outward diffusion and loss of injected energy, a short self-flowing period, and low cumulative self-flowing oil production.

[0003] To address the issue that both excessively long and short well-shutdown times after volumetric fracturing are detrimental to horizontal well production and stability, some oilfields and universities have developed methods and experiments based on numerical simulation, gaining some insights. For example, Chinese patent application CN117521437A discloses a method for determining the reasonable well-shutdown time after volumetric fracturing in tight oil reservoirs, including the following steps: 1) Establishing an oil-water two-phase flow model to characterize the fracturing fluid invasion during the well-shutdown stage after large-scale volumetric fracturing in tight oil reservoirs; 2) Discretizing the oil-water two-phase flow model based on the finite difference method to obtain the implicit finite difference equation of the oil-water two-phase flow during the well-shutdown stage; 3) Solving the difference equation, iteratively solving for the pressure and saturation at time t+1 according to the time step until the changes in pressure and saturation are both less than a set threshold; 4) Based on the pressure and saturation obtained in step 3), plotting the distribution law of pressure field and water saturation field under different well-shutdown times, and determining the reasonable well-shutdown time based on the permeation and replacement amount. For example, Chinese invention patent CN111291460B discloses a method for determining well shut-in time. Based on multiple first-type crack stress intensity factors, multiple second-type crack stress intensity factors, friction coefficient, radius of curvature, multiple first parallel stresses, multiple first vertical stresses, and multiple fracture initiation angles, it determines multiple second normal stresses and multiple third tangential stresses. Based on cohesion, friction coefficient, multiple second normal stresses, multiple third tangential stresses, multiple fracture dip angles, and multiple fracturing fluid pressures, it determines the well shut-in time for the target well. This method accurately adjusts the well shut-in time based on the fracturing fluid pressure drop during the well shut-in period, determining the optimal shut-in time for each well. However, existing methods are relatively complex, unfavorable for large-scale application, and none of them provide a rational design for the well shut-in time after volumetric fracturing of hydrophilic unconventional horizontal oil wells.

[0004] Therefore, how to avoid energy waste caused by not shutting down the well or by improper shutting down after volumetric fracturing of horizontal wells has become a technical problem that urgently needs to be solved in this field. Summary of the Invention

[0005] To address the shortcomings of the existing technology, the present invention aims to provide a method for designing the well-sinking time after volumetric fracturing of hydrophilic unconventional oil horizontal wells, so as to achieve the technical effect of oil being seen immediately upon opening of unconventional reservoir volumetric fracturing horizontal wells.

[0006] To solve at least one of the above-mentioned technical problems, the present invention adopts the following technical solution: According to the present invention, a method for designing the well-keeping time after volumetric fracturing of a hydrophilic unconventional oil horizontal well is provided, comprising the following steps: S100, evaluating reservoir wettability to determine that the reservoir is a hydrophilic reservoir; S200, establishing a basic physical model of reservoir fluid seepage after segmented and clustered fracturing of the horizontal well, and clarifying the basic conditions for the well-keeping time design method; S300, determining the well-keeping time calculation formula based on Darcy's law and seepage velocity; S400, collecting data values ​​of each parameter in the well-keeping time calculation formula; S500, substituting the data values ​​into the well-keeping time calculation formula to calculate an equivalent and reasonable well-keeping time.

[0007] According to one embodiment of the present invention, step S100 includes: determining that the reservoir is a hydrophilic reservoir by collecting pre-well rock wettability test data or conducting wettability tests.

[0008] According to one embodiment of the present invention, step S200 includes: for horizontal well segmented and clustered fracturing, determining the specific research object and clarifying the fluid distance and seepage conditions within the reservoir.

[0009] According to one embodiment of the present invention, in step S300, the formula for calculating the well simmering time is:

[0010] In the formula, φ represents porosity; μ is the viscosity of the liquid, and its unit is Pa·s; k e The effective permeability of the matrix is ​​expressed in meters. 2 ; ΔP is the driving pressure difference, in Pa; ΔL is the distance from the center of the matrix to the main fracture, in meters; t represents the well-sealing time, measured in seconds.

[0011] According to one embodiment of the present invention, step S300 includes: The formula for calculating well shut-in time is modified based on the reservoir's oil content to obtain the modified formula for calculating well shut-in time:

[0012] In the formula, S OS The overall oil saturation of the reservoir after compression; S OB To achieve an oil saturation level that approaches equilibrium; ΔS O This represents the change in oil saturation during the well shut-in period; T1 is the corrected well-clogging time, in seconds.

[0013] According to one embodiment of the present invention, the formula for calculating the overall oil saturation of the post-pressure reservoir is:

[0014] In the formula, S OS The overall oil saturation of the reservoir after compression; S O This represents the initial oil saturation. SRV stands for horizontal well stimulation volume, measured in meters (m³). 3 ; V YZ Total fluid volume injected for horizontal well stimulation, in cubic meters (m³). 3 .

[0015] According to one embodiment of the present invention, step S300 includes: The modified well-sinking time calculation formula is converted to a different unit system to obtain a general unit system well-sinking time calculation formula:

[0016] In the formula, T2 is the well-sinking time in a general unit system, in days; α is the unit conversion factor, with a value of 11.574; S OB To achieve a near-equilibrium oil saturation level, a value of 25% is chosen.

[0017] 8. The method according to claim 7, wherein step S400 comprises: The average porosity φ of the horizontal well reservoir was determined based on neutron logging data.

[0018] According to one embodiment of the present invention, step S400 includes: Based on previous reservoir geological understanding, and combined with post-compression well pressure drop monitoring data and adjacent production well test data, well test interpretation was conducted to determine the reservoir matrix permeability k. e .

[0019] According to one embodiment of the present invention, step S400 includes: breaking the gel of the fracturing fluid sample injected into the reservoir under simulated reservoir temperature conditions, and performing a viscosity test on the broken fluid to determine the viscosity μ of the fluid at the formation temperature.

[0020] According to one embodiment of the present invention, step S400 includes: collecting the pump shutdown pressure of each section of the horizontal well fracturing operation, taking the average value as the driving pressure front term, and taking the pressure at which the reservoir pressure drop rate is predicted to be less than 0.05 MPa / d as the driving pressure difference back term, and the difference is ΔP.

[0021] According to one embodiment of the present invention, step S400 includes: determining the average oil saturation S of the horizontal well reservoir based on logging data. O Then, based on the collected basic reservoir information and fracturing stimulation data, the comprehensive oil saturation S is calculated. OS .

[0022] According to one embodiment of the present invention, step S400 includes: collecting the cluster spacing of each section of the horizontal well fracturing operation, and taking half of the average value as the seepage distance ΔL.

[0023] By adopting the above technical solution, the present invention has at least one of the following advantages compared with the prior art: 1. The design method according to the present invention is simple, quick, and feasible to use; 2. Based on the method of the present invention, considering many factors such as seepage rate and reservoir oil content, the designed well-closing time is more reasonable. After application, it accelerates the stabilization of water content, basically maintains a considerable self-flowing period, and significantly improves the cumulative self-flowing production. Attached Figure Description

[0024] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used together with the following detailed description to explain the invention, but do not constitute a limitation thereof. In the drawings: Figure 1 This is a flowchart illustrating a method for designing the well-keeping time after volumetric fracturing of a hydrophilic unconventional horizontal oil well according to an embodiment of the present invention. Figure 2 A schematic diagram of capillary force in reservoir rock pores and a schematic diagram of rock wettability experiment; Figure 3 This is a basic model for seepage between the main fractures in a segmented and clustered fracturing horizontal well; Figure 4 A diagram showing the relationship between the oil cut at the wellhead and the oil saturation of the main fracture, considering the oil-water interpenetration in the fracture. Detailed Implementation

[0025] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0026] In this document, the term "embodiment" means that a particular feature, structure, or characteristic described in connection with an embodiment may be included in at least one embodiment of the invention. The appearance of this phrase in various places throughout the specification does not necessarily refer to the same embodiment, nor is it a separate or alternative embodiment mutually exclusive with other embodiments. It will be explicitly and implicitly understood by those skilled in the art that the embodiments described herein can be combined with other embodiments.

[0027] like Figure 1 As shown, the method for designing the well-keeping time after volumetric fracturing of a hydrophilic unconventional horizontal oil well according to an embodiment of the present invention generally includes the following steps: S100, evaluates reservoir wettability, and determines that the reservoir is a hydrophilic reservoir; S200, establish a basic physical model of reservoir fluid seepage after segmented and clustered fracturing of horizontal wells, and clarify the basic conditions for the design method of well shut-in time; S300, a formula for calculating well shut-in time based on Darcy's law and seepage velocity; S400 collects data values ​​of various parameters in the well shut-in time calculation formula; S500 substitutes the data values ​​into the well shut-in time calculation formula to calculate the equivalent and reasonable well shut-in time.

[0028] Step S100 primarily involves collecting basic data and determining reservoir wettability. Because hydrophilic reservoirs possess specific wettability characteristics, the application of horizontal wells in such reservoirs requires special consideration of reservoir physical properties, fluid properties, and the interaction between the wellbore and the reservoir. Specifically, as follows... Figure 2 As shown, by collecting rock wettability test data in the early stage of well operation or by conducting wettability tests in a timely manner, it can be determined that the reservoir is a hydrophilic reservoir, so as to clarify the feasibility of achieving oil-water replacement through well shut-in.

[0029] Volumetric fracturing refers to the process of hydraulic fracturing in which natural fractures are continuously expanded and brittle rocks undergo shear slip, forming a network of interwoven natural and artificial fractures. This increases the volume of fracturing, thereby improving initial production and final recovery. Hydrophilic reservoirs typically have low permeability and high resistance to oil and gas flow. Volumetric fracturing can effectively improve the reservoir's permeability and increase oil and gas production. Well shut-in after volumetric fracturing helps optimize production. Well shut-in allows the fracturing fluid to fully diffuse within the fractures, balancing formation pressure and oil saturation, thus improving well production efficiency. Without well shut-in, direct well opening may result in ineffective flowback of fracturing fluid, wasting injection energy and increasing the cost of flowback fluid treatment. In step S200, horizontal wells can be fracturing in stages and clusters. For example, assuming that each cluster in the fracturing design can be opened through the implementation of the supporting processes and form a main fracture, the reservoir between the two clusters is taken as the specific research object to clarify the fluid distance and permeation conditions within the reservoir. Among them, seepage conditions may include seepage velocity, permeability and other seepage-related condition parameters.

[0030] In step S300, the well-clogging time calculation formula is determined based on Darcy's law and the seepage velocity. Darcy's law is a fundamental physical law describing the flow of fluids in porous media such as soil and rock. Specifically, it states that the flow rate of a fluid per unit area through a porous medium is directly proportional to the pressure gradient of the fluid in that medium and inversely proportional to the viscosity of the fluid. In an embodiment of the present invention, the seepage velocity formula (Equation 1) based on Darcy's law is used:

[0031] Combine the formulas for effective seepage velocity and time-velocity relationship.

[0032] (Equation 2):

[0033] (Formula 3):

[0034] The formula for calculating the well simmering time (Formula 4) is derived as follows:

[0035] In the formula, v is the seepage velocity, in m / s; v e The effective seepage velocity is expressed in m / s. φ represents porosity; μ is the viscosity of the liquid, and its unit is Pa·s; k e The effective permeability of the matrix is ​​expressed in meters. 2 ; ΔP is the driving pressure difference, in Pa; ΔL is the distance from the center of the matrix to the main fracture, in meters; t represents the well-sealing time, measured in seconds.

[0036] Considering the impact of different reservoir oil content differences on well shut-in time, and the rebalancing process of overall reservoir oil content after horizontal well fracturing, equation (4) needs to be modified to introduce the overall impact of oil saturation and its variation on well shut-in. In the embodiments of the present invention, the well shut-in time calculation formula is modified based on reservoir oil content to obtain the modified well shut-in time calculation formula (Equation 5):

[0037] That is, (Equation 6).

[0038] In the formula, S OS The overall oil saturation of the reservoir after compression; S OB To achieve an oil saturation level that approaches equilibrium; ΔS O This represents the change in oil saturation during the well shut-in period; T1 is the corrected well-clogging time, in seconds.

[0039] In Equation 5, S OS The comprehensive saturation value is calculated based on the original oil saturation of the reservoir, taking into account the impact of the total amount of fracturing fluid injected into the stimulated area on the overall oil saturation of the stimulated area. It is shown in Equation 7.

[0040] In the formula, S OS The overall oil saturation of the reservoir after compression; S O This represents the initial oil saturation. SRV stands for horizontal well stimulation volume, measured in meters (m³). 3 ; V YZ Total fluid volume injected for horizontal well stimulation, in cubic meters (m³). 3 .

[0041] In Equation 7, S OB One of the key aspects of this invention is the target oil saturation value for the reservoir to reach oil equilibrium after wellheading, with the goal of achieving oil breakthrough. This is the oil saturation value required for the main fracture and reservoir to reach the oil breakthrough level at the wellhead. By considering the linear relationship between oil and water phase permeability in the fractures, the wellhead oil cut corresponding to different oil saturation levels in the fractures after fluid flows into the wellbore is calculated, and a fitting plot is generated as shown below. Figure 4As shown, when the wellhead reaches the target oil content of more than 1%, the oil saturation of the fracture needs to reach 25%, and this is used as the target oil saturation for adjusting the well shut-in time.

[0042] Furthermore, considering the differences between the unit system used in the field and the International System of Units (SI), the industry-standard unit system is adopted, and a conversion factor α is introduced. In the embodiments of this invention, the unit system of the well-closing time calculation formula is converted to obtain the general unit system well-closing time calculation formula (Formula 8):

[0043] In the formula, T2 is the well-sinking time in a general unit system, in days; α is the unit conversion factor, with a value of 11.574; S OB To achieve a near-equilibrium oil saturation level, a value of 25% is chosen.

[0044] In step S400, the collection and value of each parameter in the relevant formula can be specifically referred to in the following manner.

[0045] Porosity φ: The average porosity φ of the horizontal well reservoir is determined based on neutron logging data. Neutron logging is a geophysical method that uses neutron rays to detect the formation structure and mineral content around the well. Determining the average porosity φ of the horizontal well reservoir requires obtaining raw neutron logging data from the horizontal well. The average porosity φ of the horizontal well reservoir is then calculated using the correlation between this data and the porosity φ.

[0046] Matrix effective permeability k e Based on previous reservoir geological understanding, and combined with post-pressure well stagnation monitoring data and data from adjacent production well tests, well test interpretation was conducted to determine the reservoir matrix permeability k. e .

[0047] Fluid viscosity μ: The viscosity μ of the fluid at formation temperature is determined by breaking up the fracturing fluid sample injected into the reservoir under simulated reservoir temperature conditions and testing the viscosity of the broken fluid.

[0048] Seepage pressure difference ΔP: Collect the pump shutdown pressure of each section of the horizontal well fracturing operation, take the average value as the driving pressure front term, and take the pressure at which the predicted reservoir pressure drop rate is less than 0.05MPa / d as the driving pressure difference back term. The difference is ΔP.

[0049] Overall oil saturation S OS Determine the average oil saturation S of the horizontal well reservoir based on logging data. O Then, based on the collected basic reservoir information and fracturing stimulation data, the comprehensive oil saturation S is calculated according to Equation 7. OS .

[0050] Seepage distance ΔL: Collect the cluster spacing of each section of the horizontal well fracturing operation, and take half of the average value as the seepage distance ΔL.

[0051] Finally, in step S500, based on the values ​​of each data point, the relevant formula is substituted to calculate the equivalent and reasonable well-closing time.

[0052] The following example, using the design of the well-sinking time for the A-Ping 1-2 well in the RZJ oilfield as an example, illustrates the design method for the well-sinking time after volumetric fracturing of hydrophilic unconventional oil horizontal wells according to the present invention.

[0053] The F oil layer in the RZJ oilfield is a tight sandstone reservoir. Core testing has determined its wettability to be hydrophilic. Relevant data obtained during previous exploration and evaluation are as follows: The F oil layer reservoir is dominated by channel sands, which are generally distributed in bands. Controlled by sedimentary evolution, the sand bodies exhibit significant lateral variations, showing a trend of being thicker in the southeast and thinner in the northwest. The sandstone thickness in the Q1 block is generally 23-57m, with an effective thickness of 7-14m per well and an average effective thickness of 8.7m. According to core sample analysis, the reservoir properties in the Q1 block are relatively good, with porosity generally ranging from 8% to 12%, averaging 9.37%, and permeability generally ranging from 0.02 to 0.8 mD, averaging 0.3 mD. The reservoir has poor oil-bearing potential, with oil saturation generally between 45% and 55%.

[0054] Well A-Ping 1-2 is a horizontal well deployed in the F oil layer of the RZJ oilfield. The horizontal section is 1313m long, encountering a 1313m sandstone oil layer, achieving a 100% oil layer encounter rate. Geological logging showed no oil invasion or oil stains. Oil trace level indications were found at 1239m, and fluorescence level indications at 74m, indicating poor oil content. After drilling, logging, and well logging were completed, 17 sections of 86 clusters of high-volume, high-displacement fracturing were designed and implemented, with a total fracturing proppant volume of 2366m³. 3 31796m of liquid was used 3 Construction discharge volume 6-12m 3 The pumping speed is 18-29 MPa, with an average of 22.0 MPa. Based on the basic geological data and fracturing parameters of this well, a reasonable well-shutdown time design is carried out using the horizontal well post-fracturing well-shutdown time design method aimed at achieving oil breakthrough.

[0055] (1) Collect basic data and determine reservoir wettability.

[0056] The results of previous wettability experiments in this area were collected, and the reservoir was determined to be a hydrophilic reservoir.

[0057] (2) Determine the values ​​of each parameter in the correlation formula.

[0058] (2-1) Determination of porosity φ: Based on geological data and neutron logging data, the average porosity of the reservoir in this well is determined to be φ = 12%; (2-2) Permeability k e The determination of the effective permeability k of the reservoir matrix was based on geological data and interpretation of production test data from nearby oil wells in the region. e =0.3mD; (2-3) Determination of fluid viscosity μ: The reservoir depth in this area is 2100m and the formation temperature is 95℃. The fracturing fluid was simulated at this temperature and the viscosity was tested. The experiment determined that the fluid viscosity at the formation temperature is μ=1.02mPa.s. (2-4) Determination of seepage pressure difference ΔP: The well underwent fracturing in section 17, with a pump shutdown pressure of 18-29 MPa, averaging 22.0 MPa. Considering the pressure drop pattern after fracturing of previous horizontal wells in this area, the pressure with a daily pressure drop rate below 0.05 MPa / d is approximately 6 MPa. Therefore, the seepage pressure difference is:

[0059] Table 1. Pump shutdown pressure data for each section of fracturing operation in Well A-Ping 1-2

[0060] (2-5) Overall oil saturation S OS Based on geological and logging data, the well's reservoir has an average oil saturation of 49% and a depth of 31796m. 3 Fracturing fluid was injected into the 1313m horizontal section of the stimulated area. Based on fracture monitoring data, the fracture height was 25m and the length was 240m. The overall oil saturation S in the stimulated area was affected by the dilution of the fracturing fluid. OS =47.4%;

[0061] (2-6) Determination of seepage distance ΔL: The well was subjected to 17 sections and 86 clusters of fracturing. The length of the sandstone oil layer encountered was 1313m. Therefore, the average cluster spacing was 1313 / 86m, and the seepage distance ΔL = 1313 / 86 / 2 = 7.63m. Table 2. Parameters and dimensions for calculating the equivalent well shut-in time of Well A-Ping 1-2

[0062] (3) Calculate the equivalent reasonable well simmering time based on the values ​​of each data.

[0063]

[0064] (4) The well was actually shut down for 36 days, and oil was encountered on the second day after the well was opened, achieving the goal of oil production. Compared with similar horizontal wells with a shut-down time of 7-10 days in the past, the application of this method accelerated the stabilization of water content, basically maintained a considerable self-flowing period, and significantly increased the cumulative self-flowing production.

[0065] Table 3. Comparison of water cut decline rate, self-flowing period, and cumulative self-flowing yield before and after application of the method of this invention.

[0066] The design method based on this invention has been applied to over 50 wells in the exploration and development of tight oil and sandstone-type shale oil (hydrophilic) in the Jilin Oilfield. For tight oil wells that previously required short-term shut-in periods of 7-10 days, with oil breakthrough times as long as 30 days, this method reduces the designed shut-in time to 25-35 days for similar reservoirs, resulting in oil breakthrough in 80% of the wells. For sandstone-type shale oil, this method should also be used, achieving oil breakthrough in 90% of the wells.

[0067] The preferred embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the present invention is not limited to the specific details of the above embodiments. Within the scope of the technical concept of the present invention, various simple modifications can be made to the technical solution of the present invention, and these simple modifications all fall within the protection scope of the present invention.

[0068] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. In order to avoid unnecessary repetition, the present invention will not describe the various possible combinations separately.

[0069] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the present invention, they should also be regarded as the content disclosed by the present invention.

Claims

1. A method for designing the well-keeping time after volumetric fracturing in a hydrophilic unconventional horizontal oil well, characterized in that... Includes the following steps: S100, evaluates reservoir wettability, and determines that the reservoir is a hydrophilic reservoir; S200, establish a basic physical model of reservoir fluid seepage after segmented and clustered fracturing of horizontal wells, and clarify the basic conditions for the design method of well shut-in time; S300, a formula for calculating well shut-in time based on Darcy's law and seepage velocity; S400, collect the data values ​​of each parameter in the well-closing time calculation formula; S500, substitute the data value into the well-closing time calculation formula to calculate the equivalent and reasonable well-closing time.

2. The method according to claim 1, characterized in that, Step S100 includes: By collecting pre-well rock wettability test data or conducting wettability tests, the reservoir was determined to be a hydrophilic reservoir.

3. The method according to claim 1, characterized in that, Step S200 includes: For horizontal wells, segmented and clustered fracturing is employed to identify specific research objects and clarify the fluid distance and seepage conditions within the reservoir.

4. The method according to claim 1, characterized in that, In step S300, the formula for calculating the well simmering time is: In the formula, φ represents porosity; μ is the viscosity of the liquid, and its unit is Pa·s; k e The effective permeability of the matrix is ​​expressed in meters. 2 ; ΔP is the driving pressure difference, in Pa; ΔL is the distance from the center of the matrix to the main fracture, in meters; t represents the well-sealing time, measured in seconds.

5. The method according to claim 4, characterized in that, Step S300 includes: The formula for calculating well shut-in time is modified based on the reservoir's oil content to obtain the modified formula for calculating well shut-in time: In the formula, S OS The overall oil saturation of the reservoir after compression; S OB To achieve an oil saturation level that approaches equilibrium; ΔS O This represents the change in oil saturation during the well shut-in period; please... T1 is the corrected well-clogging time, in seconds.

6. The method according to claim 5, characterized in that, The formula for calculating the overall oil saturation of the post-pressure reservoir is: In the formula, S OS The overall oil saturation of the reservoir after compression; S O This represents the initial oil saturation. SRV stands for horizontal well stimulation volume, measured in meters (m³). 3 ; V YZ Total fluid volume injected for horizontal well stimulation, in cubic meters (m³). 3 .

7. The method according to claim 5, characterized in that, Step S300 includes: The modified well-sinking time calculation formula is converted to a different unit system to obtain a general unit system well-sinking time calculation formula: In the formula, T2 is the well-sinking time in a general unit system, in days; α is the unit conversion factor, with a value of 11.574; S OB To achieve a near-equilibrium oil saturation level, a value of 25% is chosen.

8. The method according to claim 7, characterized in that, Step S400 includes: The average porosity φ of the horizontal well reservoir was determined based on neutron logging data.

9. The method according to claim 7, characterized in that, Step S400 includes: Based on previous reservoir geological understanding, and combined with post-compression well pressure drop monitoring data and adjacent production well test data, well test interpretation was conducted to determine the reservoir matrix permeability k. e .

10. The method according to claim 7, characterized in that, Step S400 includes: The fracturing fluid samples injected into the reservoir were broken up under simulated reservoir temperature conditions, and the viscosity of the broken fluid was tested to determine the viscosity μ of the fluid at the formation temperature.

11. The method according to claim 7, characterized in that, Step S400 includes: Collect the pump shutdown pressures of each section of the horizontal well during fracturing operations, take the average value as the driving pressure front term, and take the pressure at which the predicted reservoir pressure drop rate is less than 0.05 MPa / d as the driving pressure back term. The difference is ΔP.

12. The method according to claim 7, characterized in that, Step S400 includes: Determine the average oil saturation S of the horizontal well reservoir based on logging data. O Then, based on the collected basic reservoir information and fracturing stimulation data, the comprehensive oil saturation S is calculated. OS .

13. The method according to claim 7, characterized in that, Step S400 includes: Collect the cluster spacing of each section of the horizontal well fracturing operation, and take half of the average value as the seepage distance ΔL.

Images