A method and apparatus for determining complex fluid saturations in carbonate reservoirs

Abstract

A method and device for determining complex fluid saturation of a carbonate reservoir, the method comprising: determining an initial complex fluid interface of the reservoir based on formation pressure test data; determining an oil column height of each single point according to the initial complex fluid interface; converting the oil column height of each single point into a capillary pressure at the corresponding position under an actual fluid system of the reservoir according to an oil column height conversion pressure formula; comparing and analyzing the determined capillary pressure under the actual fluid system of the reservoir with a logging interpreted saturation to obtain a corrected free fluid curve; determining a correlation coefficient in a saturation height function according to the corrected free fluid curve and in combination with characteristics of the complex fluid carbonate reservoir; and obtaining a saturation height function according to the determined correlation coefficient and calculating a fluid saturation of the reservoir by using the saturation height function.

Description

Technical Field

[0001] This article relates to the field of oilfield exploration and development technology, and in particular to a method and apparatus for determining the saturation of complex fluids in carbonate reservoirs. Background Technology

[0002] Since the publication of the Archie formula in 1942, the study of reservoir water saturation using well logging methods has entered a period of rapid development. The Archie formula solved the problem of calculating water saturation in classic sandstone and mudstone profiles. However, with the continuous development of oil and gas exploration and the increasing complexity of development methods and reservoir types, the Archie formula can no longer meet the accuracy requirements for saturation evaluation of different lithologies and complex fluids. For different types of carbonate reservoirs both domestically and internationally, experts and scholars have adopted different methods to study water saturation models. For the saturation characterization of complex fluid carbonate gas reservoirs in central Sichuan, characterization was performed using sequential Gaussian simulation interpolation based on single-well saturation logging interpretation data. Similarly, for the saturation characterization of complex fault-block oil and gas reservoirs in the Nanbaxian oil and gas field of the Qaidam Basin, the oil, gas, and water three-phase saturation characterization was performed by region based on single-well saturation logging interpretation results. In the saturation characterization of the X gas field in the Xihu Depression of the East China Sea, the J-function was used to calculate the saturation of a single well and correct the logging interpretation results of that well. Inter-well constraints were also used to reflect the reservoir saturation field. In the development of oil fields abroad, the methods for characterizing the saturation of oil and gas reservoirs vary. For saturation modeling with transition zones, the Archie saturation method shows certain limitations. A saturation-height function combining different lithologies and average porosity as variables is an effective solution. For the F reservoir in the Zagros Basin, a saturation-height function constraint modeling method coupled with sedimentary facies and petrophysical types was used to achieve a refined characterization of the saturation field.

[0003] Currently, with the increasing adoption of saturation height function modeling methods, the method of single-well saturation interpolation is gradually being replaced by saturation height function calculations based on the J function. Therefore, characterizing the saturation of complex fluids such as gas, oil, water, and transition zones in carbonate reservoirs is an urgent problem to be solved, particularly for carbonate reservoirs with complex fluid distributions. Summary of the Invention

[0004] To address the aforementioned technical problems, the present invention aims to provide a method and apparatus for determining the saturation of complex fluids in carbonate reservoirs. By accurately determining the free fluid surface, the saturation of carbonate reservoirs with complex fluid development is determined using a saturation height function, providing more accurate reservoir data for development geological research and subsequent stratigraphic adjustments.

[0005] In a first aspect, this application provides a method for determining the saturation of complex fluids in carbonate reservoirs, the method comprising:

[0006] The interface of the initial complex fluid in the reservoir was determined based on formation pressure test data;

[0007] The oil column height at a single point is determined based on the interface of the initial complex fluid.

[0008] The capillary pressure of the reservoir's actual fluid system at each location is obtained by converting the oil column height at each point into a pressure formula.

[0009] Based on the capillary pressure under the actual fluid system of the reservoir and the saturation interpreted by well logging, a comparative analysis was conducted to obtain the corrected free fluid surface.

[0010] The correlation coefficient in the saturation height function is determined based on the corrected free fluid surface and the characteristics of complex fluid carbonate reservoirs.

[0011] The saturation height function is obtained based on the determined correlation coefficient, and the fluid saturation of the reservoir is calculated using the saturation height function.

[0012] Secondly, embodiments of the present invention also provide an apparatus for determining the saturation of complex fluids in carbonate reservoirs, the apparatus comprising: a memory and a processor; the memory is used to store a program for determining the saturation of complex fluids in carbonate reservoirs, and the processor is used to read and execute the program for determining the saturation of complex fluids in carbonate reservoirs, and to execute the method described in any one of the above embodiments.

[0013] Thirdly, embodiments of the present invention also provide a computer-readable storage medium storing a data processing program, wherein the data processing program is executed by a processor according to any one of the above embodiments, the method for determining the saturation of complex fluids in carbonate reservoirs.

[0014] Compared with related technologies, this application provides a method and apparatus for determining the saturation of complex fluids in carbonate reservoirs. The method includes: determining the interface of the initial complex fluids in the reservoir based on formation pressure test data; determining the oil column height at a single point according to the interface of the initial complex fluids; converting the oil column height at each single point into a pressure formula to obtain the capillary pressure under the actual fluid system of the reservoir at the corresponding location; comparing and analyzing the determined capillary pressure under the actual fluid system of the reservoir with the saturation interpreted from well logging to obtain a corrected free fluid surface; determining the correlation coefficient in the saturation height function based on the corrected free fluid surface and the characteristics of the complex fluid carbonate reservoir; obtaining the saturation height function based on the determined correlation coefficient, and calculating the fluid saturation of the reservoir using the saturation height function. This application, by accurately determining the free fluid surface and using the saturation height function to determine the saturation of carbonate reservoirs with complex fluid development, provides more accurate reservoir data for development geological research and subsequent stratigraphic adjustments.

[0015] Other features and advantages of this application will be set forth in the following description, and will be apparent in part from the description, or may be learned by practicing the application. Other advantages of this application can be realized and obtained by means of the solutions described in the description and the accompanying drawings. Attached Figure Description

[0016] The accompanying drawings are used to provide an understanding of the technical solutions of this application and constitute a part of the specification. They are used together with the embodiments of this application to explain the technical solutions of this application and do not constitute a limitation on the technical solutions of this application.

[0017] Figure 1 This is a flowchart illustrating the method for determining the saturation of complex fluids in carbonate reservoirs according to an embodiment of this application.

[0018] Figure 2 This is a schematic diagram of an apparatus for determining the saturation of complex fluids in carbonate reservoirs according to an embodiment of this application;

[0019] Figure 3 This is a schematic diagram of a complex fluid interface in some exemplary embodiments;

[0020] Figure 4 This is a complex fluid interface diagram of the K reservoir in the H oilfield based on formation pressure test MDT test data in some exemplary embodiments;

[0021] Figure 5 The parameter models for the complex fluid saturation height function in the K reservoir of the H oilfield are provided in some exemplary embodiments.

[0022] Figure 6 This is a profile of a complex fluid saturation height function model for the K reservoir in the H oilfield, as shown in some exemplary embodiments.

[0023] Figure 7 Single-well error analysis of complex fluid saturation height function in K reservoir of H oilfield for some exemplary embodiments. Detailed Implementation

[0024] This application describes several embodiments, but these descriptions are exemplary and not limiting, and it will be apparent to those skilled in the art that many more embodiments and implementations are possible within the scope of the embodiments described herein. Although many possible combinations of features are shown in the drawings and discussed in the detailed description, many other combinations of the disclosed features are also possible. Unless specifically limited, any feature or element of any embodiment may be used in combination with or in lieu of any other feature or element in any other embodiment.

[0025] This application includes and contemplates combinations of features and elements known to those skilled in the art. The embodiments, features, and elements disclosed in this application may also be combined with any conventional features or elements to form a unique inventive scheme as defined by the claims. Any feature or element of any embodiment may also be combined with features or elements from other inventive schemes to form another unique inventive scheme as defined by the claims. Therefore, it should be understood that any feature shown and / or discussed in this application may be implemented individually or in any suitable combination. Therefore, the embodiments are not limited except by the limitations imposed by the appended claims and their equivalents. Furthermore, various modifications and changes may be made within the scope of the appended claims.

[0026] Furthermore, in describing representative embodiments, the specification may have presented methods and / or processes as a specific sequence of steps. However, the method or process should not be limited to the specific order of steps described herein, to the extent that it does not depend on such a specific order. As will be understood by those skilled in the art, other sequences of steps are also possible. Therefore, the specific order of steps set forth in the specification should not be construed as a limitation of the claims. Moreover, the claims concerning the method and / or process should not be limited to the steps performed in the written order, and those skilled in the art will readily understand that these orders can be varied and still remain within the spirit and scope of the embodiments of this application.

[0027] The applicant obtained a complex fluid saturation height function based on rock classification and mercury injection experiments, well logging saturation interpretation results, and the density distribution of complex fluid free water / oil-gas interfaces and different fluids based on formation pressure tests. The saturation height function calculation results and the saturation interpretation conclusions of conventional and special well logging were cross-validated to determine the fitting coefficients. The fitting parameters (Swirr, Pd, N) and rock physical parameters (K, φ) for each sample were obtained. The relationship between different parameters and rock physical data was fitted to truly reflect the distribution of different fluids such as underground gas, gas / oil transition zone, oil, oil / water transition zone, and water.

[0028] Based on the above summary, a method for determining the saturation of complex fluids in carbonate reservoirs is proposed.

[0029] This invention provides a method for determining the saturation of complex fluids in carbonate reservoirs, such as... Figure 1 As shown, the method includes steps S1-S6:

[0030] S1: Determine the interface of complex fluids in the initial reservoir based on formation pressure test data;

[0031] S2: Determine the oil column height at a single point based on the interface of the initial complex fluid;

[0032] S3: Convert the oil column height at each point into pressure using the oil column height conversion formula to obtain the capillary pressure of the actual fluid system in the reservoir at the corresponding location;

[0033] S4: Based on the capillary pressure under the actual fluid system of the reservoir and the saturation interpreted by well logging, a comparative analysis is conducted to obtain the corrected free fluid surface;

[0034] S5: Determine the correlation coefficient in the saturation height function based on the corrected free fluid surface and the characteristics of complex fluid carbonate reservoirs;

[0035] S6: Obtain the saturation height function based on the determined correlation coefficient, and use the saturation height function to calculate the fluid saturation of the reservoir.

[0036] In one exemplary embodiment, in step S1, determining the interface of the initial reservoir complex fluids based on formation pressure test data includes:

[0037] Step 11: Obtain formation pressure test data from multiple wells before or during the initial stage of reservoir production. This formation pressure test data includes depth data and formation pressure data.

[0038] Step 12: Filter the formation pressure test data, and use the filtered formation pressure test data to perform linear fitting to obtain the pressure-depth fitting lines for oil, gas and water respectively.

[0039] The standard for selecting formation pressure test data is the original formation pressure before reservoir development. Specifically, the selection criteria include test well data from before reservoir development or test well data from production wells that have not yet had an impact. Figure 3 As shown.

[0040] Step 13: Based on the pressure-depth fitting lines of oil, gas, and water, preliminarily determine the free oil-water interface depth, free gas-water interface depth, and free gas-oil interface depth of the complex fluids in the reservoir.

[0041] In step 13, the specific implementation process is as follows:

[0042] The intersection of the pressure-depth fitting lines for oil and water is determined as the depth of the free oil-water interface by using the pressure-depth fitting lines for oil and water.

[0043] The intersection of the two fitting lines, namely the pressure-depth fitting line of gas and the pressure-depth fitting line of water, is determined as the depth of the free gas-water interface.

[0044] The intersection of the oil pressure-depth fitting line and the gas pressure-depth fitting line is determined as the depth of the free oil-gas interface.

[0045] In one exemplary embodiment, in step S3, the oil column height at each single point is converted into pressure using the oil column height-to-pressure formula to obtain the capillary pressure of the actual reservoir fluid system at the corresponding location; the oil column height-to-pressure formula is:

[0046] Pcres=ρ diff_fluid ×g×HAFWL

[0047] In the above formula, Pcres is the capillary pressure under reservoir conditions, and ρ diff_fluid denoted as the density difference between different fluids, g as the acceleration due to gravity, and HAFWL as the oil column height corresponding to different fluid interfaces.

[0048] In one exemplary embodiment, in step S4, a comparative analysis is performed based on the determined capillary pressure under the actual reservoir fluid system and the well logging interpretation saturation to obtain the corrected free fluid surface. The specific process is as follows:

[0049] Step S41: Using the free interface depth of the reservoir fluid as a reference surface, determine the capillary pressure of the actual reservoir fluid system at the oil column height of each well.

[0050] Step S42: Calculate the saturation data of the well by combining the capillary pressure of the actual fluid system of the reservoir under the oil column height of each well with the saturation height function;

[0051] Step S43: Compare and analyze the saturation data calculated based on the saturation height function with the saturation data interpreted through single-well Archie logging;

[0052] Step S44: Determine the free fluid interface value of each well based on the comparative analysis results, and use the free fluid interface values ​​of multiple wells to interpolate and obtain the corrected free fluid surface.

[0053] In this step, the free fluid interface value for each well is determined based on the comparative analysis results, including:

[0054] If the difference between the saturation data calculated based on the saturation height function and the saturation data interpreted by single-well Archie logging is less than or equal to a preset threshold, then the value of the reference surface is taken as the free fluid interface value at the well point location.

[0055] If the difference between the saturation data calculated based on the saturation height function and the saturation data interpreted by single-well Archie logging does not meet the preset threshold, the reference surface is adjusted, and the free fluid interface value at the well point location is re-determined based on the adjusted reference surface.

[0056] In one exemplary embodiment, the relevant parameters of the Bruce-Corey saturation height function are determined:

[0057] Swirr, Pd, N, ρ 气 ρ 油 and ρ 水 Where SWIRR, Pd, and N are variables, and the rest can be obtained from the test data. The variables need to be linearly regressed with the rock physical data (K, φ, R35) to obtain the expression formula. There can be one or more rock physical data.

[0058] The saturation height function is:

[0059]

[0060] In the above formula, Swirr represents the degree of bound water saturation, expressed as a percentage (%).

[0061] Pce is the discharge pressure, measured in megapascals (MPa).

[0062] N is a parameter related to the pore size distribution.

[0063] Pcres is the capillary pressure.

[0064] This capillary pressure is the capillary pressure converted from the oil column height, and the conversion formula is:

[0065] Pcres=ρ diff_fluid ×g×HAFWL diff_fluid (3)

[0066] In the formula: ρ diff_fluid This represents the density difference between different fluids, expressed in grams per cubic centimeter (g / cm³). 3 ;

[0067] g is the acceleration due to gravity, measured in meters per second squared (m / s²). 2 HAFWL represents the height of the oil column above different fluid interfaces.

[0068] HAFWL is the height above the free fluid interface. Given the free fluid interface, it can be obtained by calculating the vertical distance from this point to the free fluid interface, in meters (m).

[0069] In one exemplary embodiment, in step S6, a saturation height function is obtained based on the determined correlation coefficient, and the fluid saturation of the reservoir is calculated using the saturation height function. After calculating the fluid saturation of the reservoir, it is compared with the saturation value obtained by core distillation and through-casing saturation logging, and the absolute error is less than or equal to 5%. If the error is greater than 5%, the saturation height function needs to be readjusted.

[0070] Secondly, embodiments of the present invention also provide an apparatus for determining the saturation of complex fluids in carbonate reservoirs, such as... Figure 2 As shown, the device includes a memory 200 and a processor 210; the memory is used to store a program for determining the saturation of complex fluids in carbonate reservoirs, and the processor is used to read and execute the program for determining the saturation of complex fluids in carbonate reservoirs, and to execute the method described in any of the above embodiments.

[0071] Thirdly, embodiments of the present invention also provide a computer-readable storage medium storing a data processing program, wherein the data processing program is executed by a processor according to any one of the above embodiments, the method for determining the saturation of complex fluids in carbonate reservoirs.

[0072] Example 1

[0073] The K reservoir in the H oilfield is dominated by shallow-water, gently sloping carbonate sedimentary rocks, featuring an anticline with a gas cap, oil reservoir, and edge water. Low-permeability reservoirs with an average permeability below 10 mD are the most promising for rapid production. Currently, the K reservoir exhibits complex dynamic and static characteristics, with strong reservoir heterogeneity, diverse fluid types, and complex distribution. Well production dynamics vary greatly; conventional oil is found in the lower structural regions, while wells at the structural top experience degassing immediately upon commissioning, leading to a rapid increase in the gas-oil ratio. This example, using the K reservoir in the H oilfield as a case study, details the specific process of achieving refined characterization of saturation in complex fluid carbonate reservoirs, as follows:

[0074] Step 1: Determine the free fluid surface

[0075] Step 11: Obtain formation pressure test data from multiple wells before or during the initial stage of reservoir production. This formation pressure test data includes depth data and formation pressure data.

[0076] Step 12: Filter the formation pressure test data, and use the filtered formation pressure test data to perform linear fitting to obtain the pressure-depth fitting lines for oil, gas and water respectively.

[0077] Step 13: Based on the pressure-depth fitting lines of oil, gas, and water, preliminarily determine the free oil-water interface depth, free gas-water interface depth, and free gas-oil interface depth of the complex fluids in the reservoir.

[0078] The intersection of the pressure-depth fitting lines for oil and water is determined as the depth of the free oil-water interface by using the pressure-depth fitting lines for oil and water.

[0079] The intersection of the two fitting lines, namely the pressure-depth fitting line of gas and the pressure-depth fitting line of water, is determined as the depth of the free gas-water interface.

[0080] By using the pressure-depth fitting lines for oil and gas, the intersection of the two fitting lines is determined as the depth of the free oil-gas interface. For example... Figure 3 The diagram shown is a complex fluid interface diagram of reservoir K in oilfield H, determined based on MDT test data. The determined oil-gas interface depth is -2860 TVDSS, and the oil-water interface depth is -2960 TVDSS.

[0081] Step 2: Based on the free fluid interface depth determined in Step 1, convert the oil column height into capillary pressure under reservoir conditions:

[0082] The formula for converting oil column height into capillary pressure is as follows:

[0083] Pcres=ρ diff_fluid ×g×HAFWL (3)

[0084] In the formula:

[0085] Pcres is the capillary pressure under reservoir conditions;

[0086] ρ diff_fluid This represents the density difference between different fluids, expressed in grams per cubic centimeter (g / cm³). 3 ;

[0087] g is the acceleration due to gravity, measured in meters per second squared (m / s²). 2 ;

[0088] HAFWL is the height of the oil column above different fluid interfaces, in meters (m).

[0089] Taking the free oil-water interface height (-2960m) obtained in step 1 as an example, assuming the actual vertical depth below sea level at a certain point in reservoir K is -2930m, the oil column height at that point can be approximately calculated as 30m. Furthermore, according to the force balance analysis at that point, the upward buoyancy and the downward capillary pressure caused by the oil column height remain in equilibrium.

[0090] Among them, the density difference ρ of different fluids diff_fluid =ρ 油 -ρ 水 ;

[0091] Based on the density of different fluid samples obtained from PVT experiments, assuming that ρ 油 1.1 g / cm 3 , ρ 水 0.8 g / cm 3 , then ρ diff_fiuid 0.3 g / cm 3 .

[0092] Based on the determined oil column height and the density difference of different fluids, the formula for converting oil column height into capillary pressure, Pcres = 9.80 m / s, is used. 2 *0.3g / cm 3 *30000cm; then, based on unit conversion, it equals 12.78psi.

[0093] Step 3: Based on the reference surface obtained from the formation pressure test, further verification is performed using the interpretation results of single-well Archie logging and the calculation results of the saturation height function. Due to the heterogeneity of the reservoir, the reference surface height needs to be finely adjusted in some single wells to obtain the free fluid interface value at the well point. Interpolation is then used to obtain the corrected free fluid surface.

[0094] Step 4: Determine the relevant parameters of the saturation height function and determine the saturation height function.

[0095] Based on the characteristics of complex fluid carbonate reservoirs, and combined with the Bruce-Corey saturation height function method, the relevant parameters of the saturation height function are determined.

[0096] The relationship between capillary pressure and saturation was obtained based on mercury intrusion porosimetry (MIP) experiments. Porosity was provided by conventional core experiments and well logging interpretation, while PVT experiments primarily provided gas-oil ratio, volumetric index, and density parameters. Fitting parameters for different fluid samples were obtained using MIP and PVT experiments, and regression analysis was performed using exponential or linear functions to fit the relationship between these parameters and the rock physical data.

[0097] The saturation height function is:

[0098]

[0099] In the formula:

[0100] Sw represents water saturation;

[0101] Swirr is the bound water saturation, expressed as a percentage (%).

[0102] Pce is the discharge pressure, measured in megapascals (MPa).

[0103] Pcres is the capillary pressure under reservoir conditions; N is a parameter related to the pore size distribution.

[0104] The example uses the porosity φ at a specific point within an oil reservoir as a variable. Regression calculations are performed on the four variables using linear functions, and the saturation at that point is calculated using a complex fluid saturation height function. Assuming a porosity of 15%, the formulas and calculations are as follows:

[0105] Saturation height function calculation parameters Parametric regression formula (concept) Calculation results Displacement pressure Pce 20*EXP(-11.34*φ) 3.65 Swirl's bound water saturation 0.149-0.0441*φ 0.14 N 2.3-3.77*φ 1.73 Pcres ρ_(diff_fluid)×g×HAFWL 12.78 Sw Swirr+(1-Swirr*(Pce / Pcres)^(1 / N) 55.68％

[0106] In this calculation, the oil column height HAFWL above the aforementioned different fluid interfaces is the oil column height determined based on the corrected free surface.

[0107] The above calculation process describes the saturation calculation at a specific point within the reservoir. To characterize the overall saturation field of the reservoir, models can be established for each parameter of the saturation height function based on the reservoir's porosity field or other rock physical parameters, such as... Figure 5 The model shows the parameter models of the complex fluid saturation height function in the K reservoir of oilfield H.

[0108] The values ​​of each parameter are determined based on the established parameter model of the reservoir complex fluid saturation height function, so as to determine the final saturation height function.

[0109] Step 5: Calculate the saturation based on the determined saturation height function.

[0110] The water saturation value is calculated using the saturation height function in step 4 above.

[0111] Step 6: Comparison of Result Errors

[0112] The water saturation value calculated based on the saturation height function should be compared with the saturation value obtained by core distillation and the saturation logging value obtained through casing. The absolute error should not exceed 5%.

[0113] The saturation height function modeling method is used to characterize the complex fluid characteristics of the K reservoir in the H oilfield. Figure 6 This method can effectively distinguish different fluid interfaces and characterize the contact relationships and related features of tilted fluids. Simultaneously, comparing the interpretation results of the saturation height function with the interpretation conclusions of single-well Archie saturation logging, the error was found to be relatively small. Figure 7 This meets the model quality inspection requirements.

[0114] This method was applied to calculate the saturation of over 300 wells in carbonate reservoirs in the Middle East. The results were compared with well logging interpretations and saturation logging data, showing a consistency rate of over 95%, accurately characterizing the reservoir's saturation field. This provides conditions for development geological research and geological modeling, and lays a solid foundation for subsequent reservoir development.

[0115] It will be understood by those skilled in the art that all or some of the steps, systems, or apparatuses disclosed above, and their functional modules / units, can be implemented as software, firmware, hardware, or suitable combinations thereof. In hardware implementations, the division between functional modules / units mentioned above does not necessarily correspond to the division of physical components; for example, a physical component may have multiple functions, or a function or step may be performed collaboratively by several physical components. Some or all components may be implemented as software executed by a processor, such as a digital signal processor or microprocessor, or as hardware, or as an integrated circuit, such as an application-specific integrated circuit (ASIC). Such software may be distributed on a computer-readable medium, which may include computer storage media (or non-transitory media) and communication media (or transient media). As is known to those skilled in the art, the term computer storage media includes volatile and non-volatile, removable and non-removable media implemented in any method or technology for storing information (such as computer-readable instructions, data structures, program modules, or other data). Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technologies, CD-ROM, digital versatile disc (DVD) or other optical disc storage, magnetic cartridges, magnetic tape, disk storage or other magnetic storage devices, or any other medium that can be used to store desired information and can be accessed by a computer. Furthermore, it is well known to those skilled in the art that communication media typically contain computer-readable instructions, data structures, program modules, or other data in modulated data signals such as carrier waves or other transmission mechanisms, and may include any information delivery medium.

Claims

1. A method for determining the saturation of complex fluids in carbonate reservoirs, characterized in that, The method includes: The interface of the initial complex fluid in the reservoir was determined based on formation pressure test data; The oil column height at a single point is determined based on the interface of the initial complex fluid. The oil column height is converted into pressure using the formula to obtain the capillary pressure of the actual reservoir fluid system at the corresponding location. Based on the comparative analysis of capillary pressure and well logging interpretation saturation under the actual fluid system of the reservoir, the interface of the initial complex fluid is corrected to obtain the corrected free fluid surface. Based on the corrected free fluid surface and combined with the characteristics of complex fluid carbonate reservoirs, the correlation coefficient in the saturation height function is determined; The saturation height function is obtained based on the determined correlation coefficient, and the fluid saturation of the reservoir is calculated using the saturation height function.

2. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 1, characterized in that, The determination of the interface of the initial complex fluid in the reservoir based on formation pressure test data includes: Obtain formation pressure test data that meets the standards; wherein, the formation pressure test data includes depth data and formation pressure data; Linear fitting is performed on the depth data and the formation pressure data to obtain pressure fitting curves for various fluids; the pressure fitting curves for the fluids include: pressure-depth fitting lines for oil, pressure-depth fitting lines for gas, and pressure-depth fitting lines for water. The depth of the free interface of the reservoir fluid is determined based on the pressure fitting curve of the fluid, and the interface of the initial complex fluid in the reservoir is determined based on the depth of the free interface of the reservoir fluid.

3. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 2, characterized in that, The process of determining the free interface depth of reservoir fluids based on the pressure fitting curve of the fluid is as follows: By fitting the pressure depth of oil and the pressure depth of water, the intersection of the two fitting lines is determined, and the depth corresponding to the intersection point is the free oil-water interface depth. By fitting the pressure depth of gas and the pressure depth of water, the intersection of the two fitting lines is determined, and the depth corresponding to the intersection point is the free gas-water interface depth. By fitting the pressure depth of oil and the pressure depth of gas, the intersection point of the two fitted lines is determined, and the depth corresponding to the intersection point is the free oil-gas interface depth.

4. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 3, characterized in that, The formula for converting oil column height to pressure is: Pcres=ρ diff_fluid ×g×HAFWL In the above formula, Pcres is the capillary pressure under reservoir conditions, and ρ diff_fluid denoted as the density difference between different fluids, g as the acceleration due to gravity, and HAFWL as the oil column height corresponding to different fluid interfaces.

5. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 4, characterized in that, The process involves comparing and analyzing the capillary pressure under the actual fluid system of the reservoir with the saturation interpreted from well logging, and correcting the interface of the initial complex fluid to obtain the corrected free fluid surface, including: Using the interface of the initial complex fluid in the reservoir as a reference surface, the capillary pressure of the actual fluid system in the reservoir at the oil column height of each well is determined. The saturation data of each well is obtained by calculating the capillary pressure of the actual fluid system in the reservoir at the oil column height of each well, combined with the saturation height function. The saturation data calculated based on the saturation height function and the saturation data interpreted by single-well Archie logging are compared and analyzed. Based on the comparative analysis results, the free fluid interface value of each well was determined, and the free fluid interface values ​​of multiple wells were interpolated to obtain the corrected free fluid surface.

6. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 5, characterized in that, The process of determining the free fluid interface value for each well based on the comparative analysis results is as follows: If the difference between the saturation data calculated based on the saturation height function and the saturation data interpreted by single-well Archie logging is less than or equal to a preset threshold, then the value of the reference surface is taken as the free fluid interface value at the well point location. If the difference between the saturation data calculated based on the saturation height function and the saturation data interpreted by single-well Archie logging does not meet the preset threshold, the reference surface is adjusted, and the free fluid interface value at the well point location is re-determined based on the adjusted reference surface.

7. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 1, characterized in that, The determination of the correlation coefficient in the saturation height function based on the corrected free fluid surface and the characteristics of complex fluid carbonate reservoirs includes: Obtain relevant rock physical parameters for different fluid samples; Regression fitting was performed on the obtained rock physical parameters to obtain the fitting curves for the displacement pressure Pce, bound water saturation Swirr, and N parameters, respectively. The capillary pressure Pcres curve under reservoir conditions at the corresponding oil column height is determined based on the corrected free fluid surface.

8. The method for determining the saturation of complex fluids in carbonate reservoirs according to claim 6, characterized in that, The saturation height function is: In the above formula, Sw is the water saturation, Swirr is the bound water saturation, Pce is the displacement pressure, Pcres is the capillary pressure under reservoir conditions, and N is a parameter related to pore size distribution.

9. An apparatus for determining the saturation of complex fluids in carbonate reservoirs, characterized in that, The apparatus includes a memory and a processor; the memory is used to store a program for determining the saturation of complex fluids in carbonate reservoirs, and the processor is used to read and execute the program for determining the saturation of complex fluids in carbonate reservoirs, and to execute the method according to any one of claims 1-8.

10. A computer-readable storage medium storing a data processing program, the data processing program being executed by a processor according to any one of claims 1-8, the method for determining complex fluid saturation in carbonate reservoirs.

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