A method and device for determining a main section of a deep profile control plug for a fractured-porous carbonate reservoir

Abstract

The present application relates to a kind of fracture pore type carbonate reservoir deep profile control main plug determination method and device, the method comprises: the geological data of the obtained target work area each well pair is inverted, determines the interwell fracture channel characteristic parameter of well pair;According to the interwell fracture channel characteristic parameter of each well pair and the mapping relationship between the preset interwell fracture channel characteristic parameter and interwell fracture development degree, determine the interwell fracture development type of well pair;According to the interwell fracture development type of each well pair obtained, determine the main plug combination of injection well;Using different amount of main plug combination of injection well, carry out deep profile control simulation, determine the optimal main plug combination amount.The present application solves the problem that the existing method is applied to fracture pore type carbonate reservoir profile control and is caused by the lack of "single well individualization" design to lead to the problem of poor oil-increasing effect and economic benefit, so that fracture pore type carbonate reservoir deep profile control classification grading design scientific decision-making can be realized.

Description

Technical Field

[0001] This invention relates to a method and apparatus for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs. Background Technology

[0002] For fractured and porous carbonate rocks, during water injection development, the heterogeneity of the formation and fluids due to differences in the original sedimentary environment of the reservoir, coupled with other unreasonable production measures, easily leads to the formation of water-dominant channels in the high-permeability zone. This causes injected water to surge along these channels, resulting in inefficient or ineffective water drive circulation, reservoir water flooding, or the formation entering a high-water-cut phase. The ineffective extraction of large amounts of injected water not only increases production costs such as energy consumption and wastewater treatment but also causes environmental pollution. To eliminate or reduce the hazards caused by water channeling, conventional profile control techniques typically utilize various measures such as stratified injection, chemical water shut-off, and profile control to block or limit the water absorption of high-permeability layers in injection wells, activate or increase the water absorption of low-permeability layers, and improve the water drive sweep efficiency, thereby improving the water drive effect. Among these, deep profile control using chemical agents and their supporting technologies is one of the most effective methods to improve the water drive development effect and increase the recovery rate in severely heterogeneous reservoirs during the high-water-cut period. Targeted profile control and water shut-off measures are particularly important for the efficient and economical development of oil reservoirs.

[0003] In deep profile control practices in fractured and porous carbonate reservoirs, chemical profile control methods have employed chromium acetate gel, polymer gel + KZ plugging agent, and EMKO, as well as water-drive flow direction modifiers + two-liquid gel methods. However, these methods have proven ineffective. While high-intensity, small-scale profile control can resolve profile discrepancies, injected water can re-enter the highly absorbent layer along permeable strata, resulting in unsatisfactory wellhead performance. In two-liquid gel methods, the large single injection volume of both working fluids leads to insufficient contact and incomplete gel formation, limiting the plugging effect of the two-liquid profile control agent. The water-drive flow direction modifier plays a dominant role, failing to achieve deep profile control.

[0004] The analysis reveals the reasons for the poor performance of conventional profile control techniques in carbonate reservoirs. Carbonate reservoirs simultaneously develop "pores and fractures," exhibiting characteristics of "strong microscopic heterogeneity and weak macroscopic heterogeneity." The degree of fracture development varies significantly between different well pairs. Conventional well blockade designs for well areas or well groups do not consider these differences in fracture development, failing to meet the requirements for normal profile control and water shut-off in carbonate reservoirs. Therefore, a refined "one-well-one-policy" deep profile control design is needed. This involves first classifying different types of fracture development and then designing different deep profile control slug combinations for each type. The challenges include: how to extract the characteristics of fracture development and how to design different deep profile control main slugs based on these characteristics. Summary of the Invention

[0005] In view of the above problems, it is necessary to propose a method and apparatus for determining the main sluice plug in deep drift control of fractured and porous carbonate reservoirs to solve or partially solve the above problems. The technical solution proposed by this invention is as follows:

[0006] In a first aspect, the present invention provides a method for determining the main sluice plug in deep drift control of fractured and porous carbonate reservoirs, comprising:

[0007] The geological data of each well pair in the target work area are inverted to determine the characteristic parameters of the inter-well fracture channels of the well pair;

[0008] Based on the characteristic parameters of the inter-well fracture channels of each well pair and the preset mapping relationship between the characteristic parameters of the inter-well fracture channels and the degree of inter-well fracture development, the inter-well fracture development type of the well pair is determined.

[0009] Based on the obtained inter-well fracture development types of each well pair and the mapping relationship between the preset inter-well fracture development types and the main slug combination, the main slug combination of the injection well is determined.

[0010] By using different amounts of the main slug combination in the injection well, deep-level displacement simulation was conducted to determine the optimal amount of main slug combination.

[0011] In one or more embodiments, the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development is obtained in the following ways:

[0012] Geological data of a predetermined number of well pairs with known inter-well fracture development levels are inverted to determine the characteristic parameters of inter-well fracture channels for each well pair;

[0013] Clustering is performed on the inter-well fracture channel characteristic parameters of each well pair to obtain the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development.

[0014] In one or more embodiments, the inter-well fracture channel characteristic parameters include the inter-well fracture channel size, the inter-well fracture connectivity, and the inter-well fracture permeability; the step of clustering the obtained inter-well fracture channel characteristic parameters of each well pair to obtain the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development includes:

[0015] Clustering was performed on the inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability of each well pair. The cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture were used to characterize the inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability, respectively. The mapping relationship between the cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture and the degree of inter-well fracture development was obtained.

[0016] In one or more embodiments, the inter-well fracture channel characteristic parameters include the inter-well fracture channel size, the inter-well fracture connectivity, and the inter-well fracture permeability; determining the inter-well fracture development type of the well pair based on the inter-well fracture channel characteristic parameters of each well pair and a preset mapping relationship between the inter-well fracture channel characteristic parameters and the degree of inter-well fracture development includes:

[0017] The cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture are used to characterize the scale of the inter-well fracture channel, the degree of inter-well fracture connectivity, and the permeability of the inter-well fracture, respectively.

[0018] Based on the obtained cavity volume multiple, logarithmic mean square of inter-well fracture aperture, and logarithmic mean of inter-well fracture aperture for each well pair, as well as the mapping relationship between the cavity volume multiple, logarithmic mean square of inter-well fracture aperture, and logarithmic mean of inter-well fracture aperture and the degree of inter-well fracture development, the inter-well fracture development type of the well pair is determined.

[0019] In one or more embodiments, the mapping relationship between the cavity volume multiple, the logarithmic root mean square deviation of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture and the degree of inter-well fracture development is determined by the following methods:

[0020] If the logarithmic mean square deviation of the fracture aperture between well pairs is less than a first preset value, then the fracture development type between well pairs is a cavity characteristic type.

[0021] If the logarithmic mean square deviation of the fracture aperture between well pairs is greater than or equal to a first preset value and the cavity volume multiple is greater than a second preset value, then the fracture development type of the well pair is a composite characteristic type.

[0022] If the logarithmic mean square deviation of the fracture aperture between well pairs is greater than or equal to a first preset value and the logarithmic mean of the fracture aperture between well pairs is less than or equal to a second preset value, then the fracture development type of the well pair is fracture characteristic type.

[0023] In one or more embodiments, determining the main slug combination of the injection well based on the obtained inter-well fracture development types of each well pair and the preset mapping relationship between inter-well fracture development types and main slug combinations includes:

[0024] The main slug combination of the well pair is determined based on the inter-well fracture development type of each well pair and the mapping relationship between the preset inter-well fracture development type and the main slug combination.

[0025] The main slug combination of each well pair is determined using the following formula 1:

[0026]

[0027] Where X represents the main slug combination of the injection well; i is the sequence number of the well pair corresponding to the injection well, i = 1, 2, ..., N; N is the number of well pairs corresponding to the injection well; X i For the i-th well pair, there is the main plug combination.

[0028] In one or more embodiments, the amount of the main slug assembly used in the injection well is calculated using the following formula 2, including:

[0029]

[0030] Where M(X) is the amount of the main slug assembly used in the injection well, m is the correction factor, and N is the number of well pairs corresponding to the injection well. i ) represents the amount of main plug assembly used in the i-th well pair.

[0031] In one or more embodiments, the mapping relationship between the preset inter-well fracture development type and the main slug assembly is determined in the following manner:

[0032] If the inter-well fracture development type is a pore-characteristic type, then the main slug assembly is a nanopolymer microsphere and a wetting modifier;

[0033] If the inter-well fracture development type is a composite characteristic, then the main slug assembly is a polymer gel and nanopolymer microspheres;

[0034] If the inter-well fracture development type is fracture-characteristic, then the main slug assembly is a polymer gel.

[0035] In one or more embodiments, the process of performing deep displacement simulations using different dosages of the main slug combination in the injection well to determine the optimal dosage of the main slug combination includes:

[0036] By using different amounts of the main slug combination in the injection well, deep displacement simulation was conducted to determine the corresponding increase in oil production and / or plane sweep efficiency.

[0037] Obtain the main slug combination dosage corresponding to the maximum increase in fuel production and / or the maximum planar sweep coefficient, and use it as the optimal main slug combination dosage.

[0038] Secondly, the present invention provides an application of the method for determining the main plug in deep turbulence-type carbonate reservoirs as described in the first aspect in deep turbulence-type carbonate reservoirs.

[0039] Thirdly, the present invention provides a device for determining the main sluice plug in deep drift control of fractured and porous carbonate reservoirs, comprising:

[0040] The inversion module is used to invert the geological data of each well pair in the target work area to determine the characteristic parameters of the inter-well fracture channel of the well pair.

[0041] The inter-well fracture development type determination module is used to determine the inter-well fracture development type of the well pair based on the inter-well fracture channel characteristic parameters of each well pair and the preset mapping relationship between the inter-well fracture channel characteristic parameters and the degree of inter-well fracture development.

[0042] The main slug combination determination module is used to determine the main slug combination of the injection well based on the obtained inter-well fracture development type of each well pair and the preset mapping relationship between the inter-well fracture development type and the main slug combination.

[0043] The optimal main slug combination dosage determination module is used to perform deep-ground displacement simulation using different dosages of the main slug combination of the injection well to determine the optimal main slug combination dosage.

[0044] Fourthly, the present invention provides a deep displacement method for fractured and porous carbonate reservoirs, comprising:

[0045] The optimal combination of main slugs, determined by the method for determining the main slugs in deep regulation and displacement of fractured and porous carbonate reservoirs as described in the first aspect, is used for deep regulation and displacement.

[0046] Fifthly, the present invention provides an application of the deep displacement method for fractured porous carbonate reservoirs described in the fourth aspect in deep displacement of fractured porous carbonate reservoirs.

[0047] In a sixth aspect, the present invention provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the method for determining the main plug of deep-seated fracturing carbonate reservoirs as described in the first aspect or the method for deep-seated fracturing carbonate reservoirs as described in the fourth aspect.

[0048] In a seventh aspect, the present invention provides an electronic device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the program to implement the method for determining the main plug of a deep fractured carbonate reservoir as described in the first aspect or the method for deep fractured carbonate reservoir regulation as described in the fourth aspect.

[0049] Based on the above technical solution, the beneficial effects of the present invention compared with the prior art are as follows: First, different types of inter-well fracture development are classified, and then different deep-drive plug combinations are designed for different types of inter-well fracture development.

[0050] The method for determining the main slug in deep slug control of fractured porous carbonate reservoirs provided in this invention first inverts the geological data of each well pair in the target work area to determine the characteristic parameters of the inter-well fracture channels, thus characterizing the inter-well fractures. Then, based on the characteristic parameters of the inter-well fracture channels for each well pair and the pre-defined mapping relationship between these parameters and the degree of inter-well fracture development, the inter-well fracture development type of the well pair is determined. This method can identify the corresponding inter-well fracture development type for different well pairs. Furthermore, based on the inter-well fracture development type of the well pair and the pre-defined mapping relationship between the inter-well fracture development type and the main slug combination, different deep slug control combinations are determined for different well pairs. This fully considers the differences in the degree of inter-well fracture development among different well pairs, solving the problem of poor oil production and economic benefits caused by the lack of "single-well personalized" design when applying existing methods to slug control in fractured porous carbonate reservoirs. This enables scientific decision-making for the classification and grading design of deep slug control in fractured porous carbonate reservoirs.

[0051] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention are realized and obtained in accordance with the structures particularly pointed out in the description, claims and drawings.

[0052] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, preferred embodiments are described below in detail with reference to the accompanying drawings. Attached Figure Description

[0053] To more clearly illustrate the specific embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the specific embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0054] Figure 1 This is a flowchart illustrating the method for determining the main plug section of a fractured and porous carbonate reservoir in deep hydraulic displacement, as provided in Embodiment 1 of the present invention.

[0055] Figure 2 This is a display of the actual effect of deep driving adjustment provided in Embodiment 2 of the present invention. Figure 1 ;

[0056] Figure 3 This is a display of the actual effect of deep driving adjustment provided in Embodiment 2 of the present invention. Figure 2 ;

[0057] Figure 4 This is a display of the actual effect of deep driving adjustment provided in Embodiment 2 of the present invention. Figure 3 ;

[0058] Figure 5 This is a schematic diagram of the device for determining the main plug section of a fractured and porous carbonate reservoir in deep water flow, as provided in Embodiment 3 of the present invention.

[0059] Figure 6 This is a schematic diagram of the structure of the electronic device provided in an embodiment of the present invention. Detailed Implementation

[0060] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0061] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numerals in different drawings denote the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with the present invention. Rather, they are merely examples of apparatuses and methods consistent with some aspects of the invention as detailed in the appended claims.

[0062] In the description of this invention, it should be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing the invention and for simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on the invention. Furthermore, the terms "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0063] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "installation," "connection," and "linking" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0064] Example 1

[0065] Research and application of chemical water shut-off and profile control technology can be traced back to the late 1950s. Before the 1970s, it was mainly used for water shut-off in oil wells, and the plugging agents were mainly cement slurry, oil-based cement, resin, and active heavy oil. In the early 1970s, with the emergence of polymers and their cross-linked gels, profile control technology for water injection wells developed rapidly. The profile control agents used were mostly strong gels, and the mechanism of action was mostly physical barrier-type plugging. In the mid-to-late 1970s, with the arrival of high water cut in oil fields, the research and application of chemical plugging agents also entered a period of rapid development. Due to different treatment purposes or objectives, various plugging agents have emerged, mostly for the purpose of deep profile control, displacement, and fluid flow diversion. Representative profile control agents mainly include cross-linked polymer weak gels, pre-cross-linked gel particles, and colloidal dispersion gels. After 2000, the research on supporting technologies for improving water drive effect based on overall deep profile control of reservoir engineering has become the focus of research on deep profile control and fluid flow diversion technology in high water cut oil fields.

[0066] Currently, cross-linked polymer weak gels and bulk-swelling particles are the most widely used deep profile control technologies in oilfields both domestically and internationally. For fractured reservoirs, most plugging systems currently used contain water glass and ordinary polymer isolation fluids (gels). Water glass plugging agents have poor erosion resistance, poor water shut-off adaptability, and short effective time; while ordinary polymer isolation fluids (gels) suffer severe leakage in fractures, and the gel size is difficult to match with the fracture aperture, resulting in poor water shut-off effect. For cavernous reservoirs, cement-based plugging agents are prone to venting and leakage, making it difficult to achieve the expected water shut-off effect; some polymer gels and microspheres have poor temperature and salt resistance, and even with a certain degree of density selectivity, they are difficult to meet the water shut-off requirements of high-temperature and high-salinity reservoirs.

[0067] In deep profile control practices in fractured and porous carbonate reservoirs, chemical profile control methods have employed chromium acetate gel, polymer gel + KZ plugging agent, and EMKO, as well as water-drive flow direction modifiers + two-liquid gel methods. However, these methods have proven ineffective. While high-intensity, small-scale profile control can resolve profile discrepancies, injected water can re-enter the highly absorbent layer along permeable strata, resulting in unsatisfactory wellhead performance. In two-liquid gel methods, the large single injection volume of both working fluids leads to insufficient contact and incomplete gel formation, limiting the plugging effect of the two-liquid profile control agent. The water-drive flow direction modifier plays a dominant role, failing to achieve deep profile control.

[0068] The analysis reveals the reasons for the poor performance of conventional profile control techniques in carbonate reservoirs. Carbonate reservoirs simultaneously develop "pores and fractures," exhibiting characteristics of "strong microscopic heterogeneity and weak macroscopic heterogeneity." The degree of fracture development varies significantly between different well pairs, and conventional well blockade designs for well areas or well groups cannot meet the requirements for normal profile control and water shut-off in carbonate reservoirs. Therefore, a refined, "one-well-one-policy" deep profile control design is needed. This involves first classifying different types of fracture development, and then designing different deep profile control slug combinations for each type. The challenges include extracting characteristics of fracture development, constructing a characterization system for fracture development, and designing different deep profile control main slugs.

[0069] Based on this, embodiments of the present invention provide a method for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs, such as... Figure 1 As shown, it includes:

[0070] S101. Perform inversion on the geological data of each well pair in the target work area to determine the characteristic parameters of the inter-well fracture channel of the well pair;

[0071] A fracture inversion method for fractured-porous carbonate reservoirs is used to obtain characteristic parameters of inter-well fracture channels between different wells in the target area. This method can be based on the patent "Method, Device, and Storage Medium for Characterizing Inter-well Seepage Channels Based on Water Drive (CN202210819160.3)". Specific steps include: obtaining geological parameters of the target reservoir; calculating equivalent fracture seepage parameters and matrix seepage parameters in the target reservoir based on the geological parameters; the equivalent fractures are formed by the series connection of horizontal fractures and matrix in the target reservoir; the equivalent fractures in the target reservoir constitute inter-well seepage channels; determining the water cut calculation model based on the equivalent fracture seepage parameters and matrix seepage parameters; obtaining the water cut change curve during the water drive process based on the water drive process parameters; and inverting the inter-well seepage channels using the water cut change curve during the water drive process. Those skilled in the art can also refer to the specific descriptions in the prior art, which are not specifically limited here.

[0072] The aforementioned geological data and dynamic / static parameters for the development of fractured porous carbonate reservoirs specifically include: reservoir thickness h, formation dip angle α, injection-production well spacing L, fracture linear density, matrix porosity φ, and matrix permeability K. m Roughness, tortuosity, and matrix influence factor c, initial moisture content f w0 The data includes: date of water cut increase, water cut curve, injection-production pressure difference Δp, viscosity of oil-water mixture μ, viscosity of oil-water mixture ρ, injection date of the corresponding injection well, and adjustment date of the corresponding injection well.

[0073] The above parameters are obtained in the following way:

[0074] Based on well logging data, the effective thickness of different perforated sections is accumulated to obtain the reservoir thickness h; based on core observation and imaging data, the formation dip angle α is obtained; based on the geodetic coordinates of each injection-production well pair, the corresponding injection-production well distance L is calculated; core fracture evaluation is performed by core sampling to obtain the fracture linear density; based on well logging data, the matrix porosity φ and the matrix permeability K are determined. m .

[0075] The roughness, the tortuosity, and the matrix influence factor c are determined based on the research results on fracture conductivity.

[0076] The initial moisture content f w0 The water cut rise date, the water cut curve, and the injection-production pressure difference Δp are determined from production dynamic data. Specifically, the water cut curve is plotted based on the monthly water cut data of the corresponding production wells, and the inflection point where the water cut begins to rise significantly is the water cut rise date. The initial water cut f is obtained by weighted averaging the water cut data of the three months prior to the production well's commissioning. w0 The injection-production pressure difference Δp is obtained based on the bottom hole pressure data of the production well and the injection well.

[0077] The viscosity μ and density ρ of the oil-water mixture are determined from formation fluid data (saturation-weighted determination).

[0078] The injection date and the adjustment date of the corresponding injection well are determined by the injection-production correspondence and production dynamic data.

[0079] The specific process for determining the above parameters can be found in the descriptions in the existing technology, and will not be repeated here.

[0080] S102. Determine the inter-well fracture development type of the well pair based on the characteristic parameters of the inter-well fracture channel for each well pair and the preset mapping relationship between the characteristic parameters of the inter-well fracture channel and the degree of inter-well fracture development.

[0081] Based on the characteristic parameters of the inter-well fracture channel and the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development, the degree of inter-well fracture development of the well pair can be classified so that different main slugs can be used according to the different degree of inter-well fracture development of different well pairs.

[0082] S103. Determine the main slug combination of the injection well based on the obtained inter-well fracture development type of each well pair and the preset mapping relationship between the inter-well fracture development type and the main slug combination.

[0083] Different main slugs were designed based on the development type of inter-well fractures in different well pairs, taking into full account the differences in the degree of inter-well fracture development in different well pairs.

[0084] S104. Using different amounts of the main slug combination of the injection well, conduct deep-level driving simulation to determine the optimal amount of main slug combination.

[0085] The design of the main slug combination dosage for the injection well was carried out, and different main slug combination dosages were used to simulate the flow regulation using numerical simulation methods. The flow regulation effect was evaluated to determine the optimal main slug combination dosage. When performing deep flow regulation in fractured and porous carbonate reservoirs, the optimal main slug combination dosage can achieve the expected flow regulation effect.

[0086] The method for determining the main slug for deep regulation and control in fractured porous carbonate reservoirs provided in this invention first inverts the geological data of each well pair in the target work area to determine the characteristic parameters of the inter-well fracture channels, thus characterizing the inter-well fractures. Then, based on the characteristic parameters of the inter-well fracture channels for each well pair and a pre-established mapping relationship between these parameters and the degree of inter-well fracture development, the type of inter-well fracture development for that well pair is determined. This method can identify the corresponding inter-well fracture development degree type for different well pairs. Furthermore, based on the inter-well fracture development type of the well pairs, different deep regulation and control slug combinations are designed for different well pairs, fully considering the differences in the degree of inter-well fracture development among different well pairs. This solves the problem of poor oil production and economic benefits caused by the lack of "single-well personalized" design when applying existing methods to regulation and control in fractured porous carbonate reservoirs, enabling scientific decision-making for the classification and grading design of deep regulation and control in fractured porous carbonate reservoirs.

[0087] In one embodiment, the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development described in S102 above is obtained in the following manner, including:

[0088] S201. Perform inversion on the geological data of a preset number of well pairs with known inter-well fracture development levels to determine the characteristic parameters of the inter-well fracture channels for each well pair.

[0089] S202. Cluster the inter-well fracture channel characteristic parameters of each well pair to obtain the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development.

[0090] The criteria for classifying different levels of inter-well fracture development refer to the numerical limits of inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability. For a predetermined number of well pairs, where the types of inter-well fracture development are known, geological data for each well pair is inverted to determine the characteristic parameters of the inter-well fracture channels. These characteristic parameters are then clustered to determine the data distribution range (i.e., numerical limits) of the characteristic parameters corresponding to each type of inter-well fracture development, thus establishing a mapping relationship between the type of inter-well fracture development and the numerical limits of inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability. Conventional clustering methods can be used, including K-means, DBSCAN, and spectral clustering. The specific clustering process can be found in existing technologies and will not be elaborated here.

[0091] In one embodiment, the inter-well fracture channel characteristic parameters include the inter-well fracture channel size, the inter-well fracture connectivity, and the inter-well fracture permeability; the clustering of the obtained inter-well fracture channel characteristic parameters of each well pair as described in S202 above to obtain the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development includes:

[0092] S2021. Cluster the inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability of each well pair, and use the cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture to characterize the inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability, respectively, to obtain the mapping relationship between the cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture and the degree of inter-well fracture development.

[0093] Among the many parameters characterizing inter-well fracture channels, this invention selects three parameters: inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability. Many parameters of reservoirs or inter-well fractures can be obtained through geological studies or dynamic inversion of inter-well fractures. Of these parameters, this invention only requires the characteristic parameters of inter-well fractures (inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability) to carry out the classification and grading design of deep-seated hydraulic displacement, thereby improving the efficiency of determining the main slug combination for deep-seated hydraulic displacement.

[0094] Specifically, it can be assumed that the inter-well fracture aperture is a random variable following a log-normal distribution, where the two variables are the logarithmic mean square of the inter-well fracture aperture and the logarithmic mean of the inter-well fracture aperture. The inventors discovered that the logarithmic mean square of the inter-well fracture aperture is related to the degree of inter-well fracture connectivity; better connectivity results in a larger logarithmic mean square of the inter-well fracture aperture. Therefore, the logarithmic mean square of the inter-well fracture aperture can be used to characterize the degree of inter-well fracture connectivity. According to the geometric rules, inter-well fracture permeability is positively correlated with the square of the fracture aperture; therefore, the logarithmic mean of the fracture aperture can be used to characterize the inter-well fracture permeability. For fractured porous carbonate reservoirs, vugs are the most important factor in the size of the inter-well fracture channel; therefore, the vug volume multiple can be used to characterize the size of the inter-well fracture channel. In summary, the size of the inter-well fracture channel, the degree of inter-well fracture connectivity, and the inter-well fracture permeability can be characterized by the vug volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture, respectively.

[0095] Therefore, this study uses cluster analysis on three characteristic parameters—inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability—and employs cavity volume multiple, logarithmic mean square deviation of inter-well fracture aperture, and logarithmic mean of inter-well fracture aperture to characterize these parameters, respectively. This yields a classification standard for different inter-well fracture development types, namely, the mapping relationship between cavity volume multiple, logarithmic mean square deviation of inter-well fracture aperture, and logarithmic mean of inter-well fracture aperture and the degree of inter-well fracture development.

[0096] The scale of the inter-well fracture channel refers to the volume of space occupied by the inter-well fracture in the reservoir, which can be the volume of the inter-well channel development or the thickness of the inter-well channel development, etc.; the degree of inter-well fracture connectivity refers to the degree of interconnection between the inter-well fractures, which can be the density of inter-well fracture development or the degree of difference between inter-well fractures obtained by dynamic inversion; the permeability of the inter-well fracture refers to the equivalent seepage capacity exhibited by the inter-well fracture, which can be the effective permeability of the inter-well fracture or the permeability difference between the inter-well fracture and the matrix.

[0097] The different inter-well fracture development types described in this embodiment of the invention include three categories: pore-characteristic, composite-characteristic, and fracture-characteristic. These three categories refer to the overall characteristics exhibited by the inter-well channel, and are not conventional reservoir type classifications. The classification criteria refer to the parameter distribution range of inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability corresponding to each type of inter-well fracture development.

[0098] In one embodiment, the degree of inter-well fracture development includes cavity characteristic type, composite characteristic type, and fracture characteristic type; the mapping relationship between the cavity volume multiple, the logarithmic root mean square deviation of inter-well fracture aperture, and the logarithmic mean of inter-well fracture aperture mentioned in S2021 above and the degree of inter-well fracture development is determined by the following methods, including:

[0099] If the logarithmic mean square deviation of the fracture aperture between well pairs is less than a first preset value, then the fracture development type between well pairs is a cavity characteristic type.

[0100] If the logarithmic mean square deviation of the fracture aperture between well pairs is greater than or equal to a first preset value and the cavity volume multiple is greater than a second preset value, then the fracture development type of the well pair is a composite characteristic type.

[0101] If the logarithmic mean square deviation of the fracture aperture between well pairs is greater than or equal to a first preset value and the logarithmic mean of the fracture aperture between well pairs is less than or equal to a second preset value, then the fracture development type of the well pair is fracture characteristic type.

[0102] The first and second preset values ​​mentioned above were obtained by cluster analysis of three characteristic parameters: the size of the fracture channel between wells, the degree of connection between wells, and the permeability between wells for different preset number of well pairs. The inventors of this invention performed cluster analysis on the data shown in Table 1 below, and the first preset value was 0.15 and the second preset value was 200.

[0103]

[0104]

[0105] Table 1

[0106] In one embodiment, the inter-well fracture channel characteristic parameters include the inter-well fracture channel size, the inter-well fracture connectivity, and the inter-well fracture permeability; the determination of the inter-well fracture development type of the well pair based on the inter-well fracture channel characteristic parameters of each well pair and a preset mapping relationship between the inter-well fracture channel characteristic parameters and the degree of inter-well fracture development, as described in S102 above, includes:

[0107] S1021. The volume ratio of the cavity, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture are used to characterize the scale of the inter-well fracture channel, the degree of inter-well fracture connectivity, and the permeability of the inter-well fracture, respectively.

[0108] S1022. Based on the obtained cavity volume multiple, logarithmic mean square deviation of inter-well fracture aperture, and logarithmic mean value of inter-well fracture aperture for each well pair, and the mapping relationship between the cavity volume multiple, logarithmic mean square deviation of inter-well fracture aperture, and logarithmic mean value of inter-well fracture aperture and the degree of inter-well fracture development determined in S2021 above, determine the inter-well fracture development type of the well pair.

[0109] After determining the three parameters of inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability, a classification-based deep-well displacement design method is established. For the pore-characteristic type, large-scale fractures are basically absent, and the pore volume ratio is moderate. Therefore, this type of inter-well channel is mainly controlled by pore and pore characteristics. For the composite-characteristic type, large-scale fractures may exist, and the pore volume ratio is the largest. Therefore, it is determined that this type of inter-well channel is mainly controlled by a combination of fracture and pore characteristics. For the fracture-characteristic type, it mainly exists in the pore-fracture development zone, with large-scale fractures and the smallest pore volume ratio. Therefore, it is determined that this type of inter-well channel is mainly controlled by fracture characteristics. Based on this, in one embodiment, the mapping relationship between the preset inter-well fracture development type and the main slug combination in S1031 is determined in the following way:

[0110] If the inter-well fracture development type is a pore-characteristic type, then the main slug assembly is a nanopolymer microsphere and a wetting modifier;

[0111] If the inter-well fracture development type is a composite characteristic, then the main slug assembly is a polymer gel and nanopolymer microspheres;

[0112] If the inter-well fracture development type is fracture-characteristic, then the main slug assembly is a polymer gel.

[0113] In one embodiment, the determination of the main slug combination of the injection well based on the obtained inter-well fracture development types of each well pair and the preset mapping relationship between inter-well fracture development types and main slug combinations as described in S103 above includes:

[0114] S1031. Determine the main slug combination of the well pair based on the inter-well fracture development type of each well pair and the mapping relationship between the preset inter-well fracture development type and the main slug combination.

[0115] S1032. Determine the main slug combination of the injection well based on the main slug combination of each well pair using the following formula 1:

[0116]

[0117] Where X represents the main slug combination of the injection well; i is the sequence number of the well pair corresponding to the injection well, i = 1, 2, ..., N; N is the number of well pairs corresponding to the injection well; X i Let X be the main plug combination for the i-th well pair. For example, if the i-th well pair has a cavity characteristic, then X i It consists of nanopolymer microspheres and a wetting regulator.

[0118] In one embodiment, the amount of the main slug assembly used in the injection well described in S104 above is calculated using the following formula 2, including:

[0119]

[0120] Where M(X) is the amount of the main slug assembly used in the injection well, m is the correction factor, and N is the number of well pairs corresponding to the injection well. i ) represents the amount of main plug assembly used in the i-th well pair.

[0121] Based on extensive theoretical and field empirical studies, the value of m ranges from 1.2 to 1.5. The reason for this value is that chemical plugging agents occupy pores and fractures in the near-wellbore zone of the injection well and migrate towards non-target well pairs. Especially for fractured carbonate reservoirs, the strong microscopic heterogeneity makes this migration effect of chemical plugging agents more significant compared to sandstone reservoirs; therefore, the minimum value of m must be greater than 1.2. M(X) i The dosage design is determined based on the principle of achieving the maximum technical or economic value of both the increase in oil volume and the plane sweep efficiency.

[0122] In one embodiment, the method described in S104 above, which involves using different dosages of the main slug combination in the injection well to perform deep displacement simulation and determine the optimal dosage of the main slug combination, includes:

[0123] S1041. Using different amounts of the main slug combination of the injection well, deep displacement simulation is performed to determine the corresponding oil increase and / or plane sweep efficiency.

[0124] S1042. Obtain the main slug combination dosage corresponding to the maximum increase in fuel production and / or the maximum planar sweep coefficient, and use it as the optimal main slug combination dosage.

[0125] Example 2

[0126] To provide a more intuitive understanding of the application effect of the method for determining the main plug of deep regulation and drive in fractured and porous carbonate reservoirs provided in Example 1, the specific implementation of the present invention will now be illustrated using the classification and grading design decision-making process of a certain fractured and porous carbonate reservoir using the above method as an example.

[0127] S301: Collect the geological parameters of each well pair. Table 2 shows the geological parameters of each well pair input in step S101 of Example 1.

[0128] S302: Invert the geological parameters of each well pair to calculate the inter-well fracture characteristic parameters for different well pairs. Table 3 shows the inter-well fracture characteristic parameters obtained using the inter-well heterogeneity massing method for fractured porous carbonate reservoirs.

[0129]

[0130] Table 3

[0131]

[0132]

[0133] Table 2

[0134] S303: Clustering and classification of three types of inter-well fracture characteristic parameters. Based on the inter-well fracture characteristic parameters (Table 3) and the classification criteria for different degrees of inter-well fracture development obtained in Example 1, typical well pairs INJ1-PRO1, INJ1-PRO2, and INJ2-PRO3 belong to fracture characteristic type, composite characteristic type, and porosity characteristic type, respectively.

[0135] S304: Determine the deep-drive main slug combination. Different deep-drive slug combinations are designed for different well-to-well fracture development levels. Well pair INJ1-PRO1 is fracture-characteristic, and the selected deep-drive main slug combination is polymer gel; well pair INJ1-PRO2 is composite-characteristic, and the selected deep-drive main slug combination is a polymer gel + nano-polymer microsphere combination; well pair INJ2-PRO3 is porosity-characteristic, and the selected deep-drive main slug combination is a combination of nano-polymer microspheres and wetting modifier; Table 4 shows the deep-drive main slug combinations for different well pairs.

[0136]

[0137] Table 4

[0138] S305: Comparison of the dosage and effect of the main slug combination for deep-seated controlled-drive. Using numerical simulation, with the maximum increase in oil production and plane sweep efficiency as the limit, the dosage of the main slug combination for the three well pairs is shown in Table 5.

[0139]

[0140] Table 5

[0141] Since the well pairs INJ1-PRO1 and INJ1-PRO2 of injection well INJ1 represent different types of inter-well fracture development, the main slug of injection well INJ1 contains both polymer gel and nanopolymer microspheres. The correction factor is a redundancy ratio set to account for the loss of plugging agents (polymer gel, nanopolymer microspheres, etc.) underground. Due to the development of pores and fractures near injection well INJ1, the correction factor m for injection well INJ1 is taken as 1.5; due to the weaker development of pores and fractures near injection well INJ2, the correction factor m for injection well INJ2 is taken as 1.2. In summary, the design of the combined amount of deep-penetration main slugs for injection wells INJ1 and INJ2 is obtained through Formula 2, as shown in Table 6.

[0142]

[0143]

[0144] Table 6

[0145] Numerical techniques were used to compare the effects, and the deep-seated water-depletion and oil-increasing effects of INJ1 and INJ2 designed using the method of this patent are significantly higher than those of conventional methods (the simulation results of the three typical models are shown in Table 7).

[0146]

[0147] Table 7

[0148] Actual effect of deep adjustment drive (e.g.) Figures 2-4 The deep-drive operation of injection wells INJ1 and INJ2 resulted in significant oil production increases. Wells PRO1, PRO2, and PRO3 increased oil production by 6124, 9720, and 1383 tons, respectively, achieving excellent economic benefits. Figure 2 , Figure 3 and Figure 4 The black line in the text indicates the date of the drive adjustment construction.

[0149] This invention proposes a method to characterize inter-well fractures using three characteristic parameters: fracture channel size, fracture connectivity, and fracture permeability. It also addresses the design of main plugs for deep-seated hydraulic displacement systems with composite, fracture, and pore characteristics. This solves the problem of poor oil production and economic benefits caused by the lack of "personalized single-well design" when applying existing methods to hydraulic displacement in fractured and porous carbonate reservoirs. This enables scientific decision-making for the classification and grading design of deep hydraulic displacement systems in fractured and porous carbonate reservoirs.

[0150] Example 3

[0151] Based on the same inventive concept, this invention provides an application of the method for determining the main plug in deep turbulence-type carbonate reservoirs as described in any of the above embodiments in deep turbulence-type carbonate reservoirs.

[0152] Based on the same inventive concept, embodiments of the present invention provide a device for determining the main sluice plug in deep-seated fracturing carbonate reservoirs, such as... Figure 5 As shown, it includes:

[0153] The inversion module 401 is used to invert the geological data of each well pair in the target work area to determine the characteristic parameters of the fracture channel between the well pairs.

[0154] The inter-well fracture development type determination module 402 is used to determine the inter-well fracture development type of the well pair based on the inter-well fracture channel characteristic parameters of each well pair and the preset mapping relationship between the inter-well fracture channel characteristic parameters and the degree of inter-well fracture development.

[0155] The main slug combination determination module 403 is used to determine the main slug combination of the injection well based on the obtained inter-well fracture development type of each well pair and the preset mapping relationship between the inter-well fracture development type and the main slug combination.

[0156] The optimal main slug combination dosage determination module 404 is used to perform deep-ground displacement simulation using different dosages of the main slug combination of the injection well to determine the optimal main slug combination dosage.

[0157] The device for determining the main sluice plug in deep fractured carbonate reservoirs provided in this embodiment of the invention has a similar implementation principle and technical effect to the method for determining the main sluice plug in deep fractured carbonate reservoirs described in the above embodiment, and will not be repeated here.

[0158] Based on the same inventive concept, embodiments of the present invention also provide a deep-seated method for regulating and driving fractured and porous carbonate reservoirs, comprising:

[0159] The optimal combination of main slugs used in deep regulation and displacement of fractured porous carbonate reservoirs, as determined by the method for determining the main slugs in any of the above embodiments, is used for deep regulation and displacement.

[0160] Based on the same inventive concept, embodiments of the present invention also provide the application of the deep displacement method for fractured porous carbonate reservoirs described in any of the above embodiments in deep displacement of fractured porous carbonate reservoirs.

[0161] Based on the same inventive concept, embodiments of the present invention also provide a computer-readable storage medium storing a computer program that, when executed by a processor, implements the method for determining the main plug of deep-seated fractured-porous carbonate reservoirs as described in any of the above embodiments, or the method for deep-seated fractured-porous carbonate reservoirs as described in any of the above embodiments.

[0162] The computer-readable storage medium may be included in the device / apparatus described in the above embodiments; or it may exist independently and not assembled into the device / apparatus. The computer-readable storage medium carries one or more programs that, when executed, implement the method according to the embodiments of the present invention.

[0163] According to embodiments of the present invention, the computer-readable storage medium may be a non-volatile computer-readable storage medium, such as including, but not limited to: portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof. In the present invention, the computer-readable storage medium may be any tangible medium containing or storing a program that can be used by or in conjunction with an instruction execution system, apparatus, or device.

[0164] Based on the same inventive concept, embodiments of the present invention also provide an electronic device, such as... Figure 6 As shown, it includes a processor 111, a communication interface 112, a memory 113 and a communication bus 114, wherein the processor 111, the communication interface 112 and the memory 113 communicate with each other through the communication bus 114.

[0165] Memory 113 is used to store computer programs;

[0166] When the processor 111 executes the program stored in the memory 113, it implements the method for determining the main plug of the deep-seated fracturing carbonate reservoir as described in any of the aforementioned method embodiments, or the method for deep-seated fracturing carbonate reservoirs as described in any of the above embodiments.

[0167] The electronic device provided in this embodiment of the invention is used to implement the method for determining the main plug of deep displacement in fractured porous carbonate reservoirs or the method for deep displacement in fractured porous carbonate reservoirs. Therefore, the electronic device also possesses the technical effects of the method for determining the main plug of deep displacement in fractured porous carbonate reservoirs or the method for deep displacement in fractured porous carbonate reservoirs, and will not be described in detail here.

[0168] The aforementioned memory 113 may be an electronic memory such as flash memory, EEPROM (Electrically Erasable Programmable Read-Only Memory), EPROM, hard disk, or ROM. Memory 113 has storage space for program code used to perform any of the method steps described above. For example, the storage space for program code may include individual program codes for implementing the various steps in the methods described above. This program code can be read from or written to one or more computer program products. These computer program products include program code carriers such as hard disks, optical discs (CDs), memory cards, or floppy disks. Such computer program products are typically portable or fixed storage units. The storage unit may have storage segments or storage spaces arranged similarly to memory 113 in the aforementioned electronic device. The program code may be compressed, for example, in a suitable form. Typically, the storage unit includes programs for performing the method steps according to embodiments of the invention, i.e., code that can be read by a processor such as 111, which, when run by the electronic device, causes the electronic device to perform the various steps in the methods described above.

[0169] In this document, relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, without necessarily requiring or implying any such actual relationship or order between these entities or operations. Furthermore, 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 a process, method, article, or apparatus. The terms "upper," "lower," etc., indicating orientation or positional relationships based on the orientation or positional relationships shown in the accompanying drawings, are used only for the convenience of describing the invention and for simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be construed as limiting the invention.

[0170] The various embodiments in this specification are described in a progressive manner. Similar or identical parts between embodiments can be referred to interchangeably. Each embodiment focuses on its differences from other embodiments. It should be noted that, unless otherwise specified, the embodiments and features described in these embodiments can be combined with each other. This invention is not limited to any single aspect, nor to any single embodiment, nor to any combination and / or substitution of these aspects and / or embodiments. Each aspect and / or embodiment of this invention can be used alone, or in combination with one or more other aspects and / or other embodiments.

[0171] Finally, it should be noted that the above-described embodiments are merely specific implementations of the present invention, used to illustrate the technical solutions of the present invention, and not to limit it. The scope of protection of the present invention is not limited thereto. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that any person skilled in the art can still modify or easily conceive of changes to the technical solutions described in the foregoing embodiments within the technical scope disclosed in the present invention, or make equivalent substitutions for some of the technical features; and these modifications, changes, or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention, and should all be covered within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs, characterized in that, include: The geological data of each well pair in the target work area are inverted to determine the characteristic parameters of the inter-well fracture channels of the well pair; Based on the characteristic parameters of the inter-well fracture channels of each well pair and the preset mapping relationship between the characteristic parameters of the inter-well fracture channels and the degree of inter-well fracture development, the inter-well fracture development type of the well pair is determined. Based on the obtained inter-well fracture development types of each well pair and the mapping relationship between the preset inter-well fracture development types and the main slug combination, the main slug combination of the injection well is determined. By using different amounts of the main slug combination in the injection well, deep-level displacement simulation was conducted to determine the optimal amount of main slug combination.

2. The method for determining the main sluice plug in deep drift control of fractured and porous carbonate reservoirs according to claim 1, characterized in that, The mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development is obtained through the following methods: Geological data of a predetermined number of well pairs with known inter-well fracture development levels are inverted to determine the characteristic parameters of inter-well fracture channels for each well pair; Clustering is performed on the inter-well fracture channel characteristic parameters of each well pair to obtain the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development.

3. The method for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs according to claim 2, characterized in that, The inter-well fracture channel characteristic parameters include the size of the inter-well fracture channel, the degree of inter-well fracture connectivity, and the inter-well fracture permeability; the clustering of the obtained inter-well fracture channel characteristic parameters for each well pair to obtain the mapping relationship between the preset inter-well fracture channel characteristic parameters and the degree of inter-well fracture development includes: Clustering was performed on the inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability of each well pair. The cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture were used to characterize the inter-well fracture channel size, inter-well fracture connectivity, and inter-well fracture permeability, respectively. The mapping relationship between the cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture and the degree of inter-well fracture development was obtained.

4. The method for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs according to claim 3, characterized in that, The inter-well fracture channel characteristic parameters include the size of the inter-well fracture channel, the degree of inter-well fracture connectivity, and the inter-well fracture permeability; the determination of the inter-well fracture development type of the well pair based on the inter-well fracture channel characteristic parameters of each well pair and a preset mapping relationship between the inter-well fracture channel characteristic parameters and the degree of inter-well fracture development includes: The cavity volume multiple, the logarithmic mean square of the inter-well fracture aperture, and the logarithmic mean of the inter-well fracture aperture are used to characterize the scale of the inter-well fracture channel, the degree of inter-well fracture connectivity, and the permeability of the inter-well fracture, respectively. Based on the obtained cavity volume multiple, logarithmic mean square of inter-well fracture aperture, and logarithmic mean of inter-well fracture aperture for each well pair, as well as the mapping relationship between the cavity volume multiple, logarithmic mean square of inter-well fracture aperture, and logarithmic mean of inter-well fracture aperture and the degree of inter-well fracture development, the inter-well fracture development type of the well pair is determined.

5. The method for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs according to claim 3, characterized in that, The degree of inter-well fracture development includes cavity characteristic type, composite characteristic type, and fracture characteristic type; the mapping relationship between the cavity volume multiple, the logarithmic root mean square deviation of inter-well fracture aperture, and the logarithmic mean of inter-well fracture aperture and the degree of inter-well fracture development is determined by the following methods, including: If the logarithmic mean square deviation of the fracture aperture between well pairs is less than a first preset value, then the fracture development type between well pairs is a cavity characteristic type. If the logarithmic mean square deviation of the fracture aperture between well pairs is greater than or equal to a first preset value and the cavity volume multiple is greater than a second preset value, then the fracture development type of the well pair is a composite characteristic type. If the logarithmic mean square deviation of the fracture aperture between well pairs is greater than or equal to a first preset value and the logarithmic mean of the fracture aperture between well pairs is less than or equal to a second preset value, then the fracture development type of the well pair is fracture characteristic type.

6. The method for determining the main plug section of deep drift control in fractured and porous carbonate reservoirs according to claim 1, characterized in that, The step of determining the main slug combination of the injection well based on the obtained inter-well fracture development types of each well pair and the preset mapping relationship between inter-well fracture development types and main slug combinations includes: The main slug combination of the well pair is determined based on the inter-well fracture development type of each well pair and the mapping relationship between the preset inter-well fracture development type and the main slug combination. The main slug combination of each well pair is determined using the following formula 1: Where X represents the main slug combination of the injection well; i is the sequence number of the well pair corresponding to the injection well, i = 1, 2, ..., N; N is the number of well pairs corresponding to the injection well; X i For the i-th well pair, there is the main plug combination.

7. The method for determining the main sluice plug in deep drift control of fractured and porous carbonate reservoirs according to claim 1, characterized in that, The amount of the main slug assembly used in the injection well is calculated using the following formula 2, including: Where M(X) is the amount of the main slug assembly used in the injection well, m is the correction factor, and N is the number of well pairs corresponding to the injection well. i ) represents the amount of main plug assembly used in the i-th well pair.

8. The method for determining the main sluice plug in deep drift control of fractured porous carbonate reservoirs according to any one of claims 6, characterized in that, The mapping relationship between the preset inter-well fracture development type and the main slug assembly is determined in the following way: If the inter-well fracture development type is a pore-characteristic type, then the main slug assembly is a nanopolymer microsphere and a wetting modifier; If the inter-well fracture development type is a composite characteristic, then the main slug assembly is a polymer gel and nanopolymer microspheres; If the inter-well fracture development type is fracture-characteristic, then the main slug assembly is a polymer gel.

9. The method for determining the main sluice plug in deep drift control of fractured and porous carbonate reservoirs according to claim 1, characterized in that, The process of using different dosages of the main slug combination in the injection well to perform deep displacement simulation and determine the optimal dosage of the main slug combination includes: By using different amounts of the main slug combination in the injection well, deep displacement simulation was conducted to determine the corresponding increase in oil production and / or plane sweep efficiency. Obtain the main slug combination dosage corresponding to the maximum increase in fuel production and / or the maximum planar sweep coefficient, and use it as the optimal main slug combination dosage.

10. The application of the method for determining the main plug of deep turbulence-type carbonate reservoirs according to any one of claims 1-9 in deep turbulence-type carbonate reservoirs.

11. A device for determining the main sluice plug in deep-seated fracturing carbonate reservoirs, characterized in that, include: The inversion module is used to invert the geological data of each well pair in the target work area to determine the characteristic parameters of the inter-well fracture channel of the well pair. The inter-well fracture development type determination module is used to determine the inter-well fracture development type of the well pair based on the inter-well fracture channel characteristic parameters of each well pair and the preset mapping relationship between the inter-well fracture channel characteristic parameters and the degree of inter-well fracture development. The main slug combination determination module is used to determine the main slug combination of the injection well based on the obtained inter-well fracture development type of each well pair and the preset mapping relationship between the inter-well fracture development type and the main slug combination. The optimal main slug combination dosage determination module is used to perform deep-ground displacement simulation using different dosages of the main slug combination of the injection well to determine the optimal main slug combination dosage.

12. A deep-penetration method for fractured-pore carbonate reservoirs, characterized in that, include: The optimal combination of main slugs used in deep regulation and displacement is determined by the method for determining the main slugs in fractured and porous carbonate reservoirs as described in any one of claims 1-9.

13. The application of the deep-seated displacement method for fractured-porous carbonate reservoirs as described in claim 12 in deep-seated displacement of fractured-porous carbonate reservoirs.

14. A computer-readable storage medium having a computer program stored thereon, characterized in that, When executed by the processor, the program implements the method for determining the main plug of deep turbulence-type carbonate reservoirs as described in any one of claims 1-9, or the method for deep turbulence-type carbonate reservoirs as described in claim 12.

15. An electronic device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the program, it implements the method for determining the main plug of deep-seated turbulence-type carbonate reservoirs as described in any one of claims 1-9, or the method for deep-seated turbulence-type carbonate reservoirs as described in claim 12.

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