Reservoir hydrocarbon saturation determination method and related equipment

Abstract

The invention discloses a method for determining hydrocarbon saturation of a logging reservoir and related equipment, and relates to the field of oil-gas exploration, and the method comprises the following steps: obtaining gas logging data and logging porosity data; the natural gas volume and gas-oil ratio data under the earth surface condition are obtained based on the gas logging data, and the gas-oil volume ratio data comprise the gas volume coefficient, the crude oil volume coefficient, the gas-oil ratio and the gas-oil ratio when the stratum pressure is bubble point pressure; the reservoir hydrocarbon saturation comprises at least one of gas saturation, oil saturation and total hydrocarbon saturation; oil gas property parameters under the earth surface condition are calculated; calculating oil and gas property parameters in the oil reservoir state based on the formation temperature and pressure conditions; the saturation state of the oil reservoir is judged based on bubble point line temperature and pressure conditions, the saturation state of the oil and gas reservoir is judged according to formation pressure and oil reservoir bubble point pressure, and the oil and gas saturation state comprises a liquid hydrocarbon single-phase state, a gaseous hydrocarbon single-phase state and an oil and gas mixed-phase state; and based on the oil reservoir saturation state, the natural gas volume under the earth surface condition, the logging porosity data and the gas-oil volume ratio data, the reservoir hydrocarbon saturation is obtained.

Description

Technical Field

[0001] This specification relates to the field of oil and gas exploration. More specifically, this application relates to a method for determining hydrocarbon saturation in a reservoir and related equipment. Background Art

[0002] The calculation of hydrocarbon saturation in oil and gas reservoirs has long been achieved based on geophysical logging data. In related technologies, the Archie formula is usually used to calculate the fluid saturation of a reservoir. However, in the practice of oil and gas exploration and development, there are perceptible errors in the reservoir fluid saturation calculated by the Archie formula, especially in the case of low resistivity oil and gas reservoirs and high resistivity water layers, where the errors are obvious.

[0003] From the perspective of the resistivity measurement mechanism and the establishment mechanism of the Archie formula, the calculation deviation stems from the appropriateness of grasping the Archie parameters a, b, m, and n. Therefore, the difficulty in accurately calculating using the Archie formula is to obtain accurate Archie parameters for the target horizon. This requires a large amount of high-cost rock-electric experiment data, which is almost impossible to achieve for oil and gas exploration companies with a wide construction area. This is also a problem encountered in well logging data interpretation technology in the past nearly a century. Summary of the Invention

[0004] A series of simplified concepts are introduced in the Summary of the Invention section, which will be further described in detail in the Detailed Description section. The Summary of the Invention section of this application does not mean to attempt to define the key features and essential technical features of the claimed technical solution, nor does it mean to attempt to determine the protection scope of the claimed technical solution.

[0005] In a first aspect, this application proposes a method for determining hydrocarbon saturation in a reservoir. The method includes:

[0006] Obtain gas logging data and logging porosity data;

[0007] Based on the gas logging data, obtain the natural gas volume and gas-oil ratio data under surface conditions. Among them, the gas-oil volume ratio data includes the gas volume coefficient, the crude oil volume coefficient, the gas-oil ratio, and the gas-oil ratio when the formation pressure is the bubble point pressure. The hydrocarbon saturation in the reservoir includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation;

[0008] Judge the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir. Among them, the saturation state of the oil and gas reservoir includes a single-phase state of liquid hydrocarbon, a single-phase state of gaseous hydrocarbon, and a miscible state of oil and gas;

[0009] Based on the saturation state of the oil and gas reservoir, the natural gas volume under the surface conditions, the logging porosity data, and the gas-oil volume ratio data, obtain the hydrocarbon saturation in the reservoir.

[0010] In one embodiment, the above gas logging data includes a degassing efficiency correction coefficient, the flow rate of the chromatograph sample gas, the net gas increment in the outlet drilling fluid, the sample gas pipeline pressure, the drilling fluid outlet temperature, the drilling fluid outlet flow rate, the surface temperature, the surface pressure, and the flow rate of the degasser drawing the drilling fluid.

[0011] The above method for obtaining the natural gas volume and gas-oil ratio data under surface conditions based on the above gas logging data includes:

[0012] Obtaining the natural gas volume under the above surface conditions based on the above degassing efficiency correction coefficient, the above chromatograph sample gas flow rate, the above net gas increment in the outlet drilling fluid, the above sample gas pipeline pressure, the above drilling fluid outlet temperature, the drilling fluid outlet flow rate, the above surface temperature, the above surface pressure, and the flow rate of the degasser drawing the drilling fluid.

[0013] In one embodiment, the above method further includes:

[0014] Determining the natural gas volume GSS under the above surface conditions based on the following formula:

[0015]

[0016] In the formula, k is the above degassing efficiency correction coefficient, Q is the above chromatograph sample gas flow rate, DTC is the above net gas increment in the outlet drilling fluid, P tube is the above sample gas pipeline pressure, T out is the above drilling fluid outlet temperature, Flrate is the above drilling fluid outlet flow rate, T S is the above surface temperature, P S is the above surface pressure, Q d is the flow rate of the degasser drawing the drilling fluid.

[0017] In one embodiment, obtaining the saturation state of the oil and gas reservoir according to the formation pressure and the oil reservoir bubble point pressure includes:

[0018] When the above formation pressure is greater than the above oil reservoir bubble point pressure, the above saturation state of the oil and gas reservoir is the above single-phase state of liquid hydrocarbons or the above single-phase state of gaseous hydrocarbons; and / or

[0019] When the above formation pressure is less than the above oil reservoir bubble point pressure, the above saturation state of the oil and gas reservoir is the above oil-gas miscible state.

[0020] In one embodiment, the above method for obtaining the hydrocarbon saturation of the reservoir based on the above saturation state of the oil and gas reservoir, the natural gas volume under the above surface conditions, the above logging porosity data, and the gas-oil volume ratio data includes:

[0021] When the saturation state of the above oil and gas reservoir is the single-phase state of the above gaseous hydrocarbon, the gas saturation is determined according to the above gas volume coefficient, the natural gas volume under the above surface conditions, and the above logging porosity data.

[0022] In one embodiment, the obtaining of the hydrocarbon saturation of the reservoir based on the saturation state of the above oil and gas reservoir, the natural gas volume under the above surface conditions, the above logging porosity data, and the gas-oil volume ratio data includes:

[0023] When the saturation state of the above oil and gas reservoir is the single-phase state of the above liquid hydrocarbon, the oil saturation is determined according to the above crude oil volume coefficient, the natural gas volume under the above surface conditions, the above gas-oil ratio, and the above logging porosity data.

[0024] In one embodiment, the obtaining of the hydrocarbon saturation of the reservoir based on the saturation state of the above oil and gas reservoir, the natural gas volume under the above surface conditions, the above logging porosity data, and the gas-oil volume ratio data includes:

[0025] When the saturation state of the above oil and gas reservoir is the oil-gas miscible state, the gas saturation is determined according to the gas-oil ratio when the above formation pressure is the bubble point pressure, the above oil-gas ratio, the above gas volume coefficient, the above crude oil volume coefficient, the natural gas volume under the above surface conditions, and the above logging porosity data;

[0026] The oil saturation is determined according to the above crude oil volume coefficient, the natural gas volume under the above surface conditions, the above gas-oil ratio, and the above porosity data;

[0027] The total hydrocarbon saturation is determined according to the gas-oil ratio when the above formation pressure is the bubble point pressure, the above oil-gas ratio, the above gas volume coefficient, the above crude oil volume coefficient, the natural gas volume under the above surface conditions, and the above porosity data.

[0028] In a second aspect, the present application also proposes a device for determining the hydrocarbon saturation of a reservoir, including:

[0029] A first obtaining unit for obtaining gas logging data and porosity data;

[0030] A second obtaining unit for obtaining the natural gas volume and gas-oil ratio data under surface conditions based on the above gas logging data, wherein the above gas-oil volume ratio data includes the gas volume coefficient, the crude oil volume coefficient, the gas-oil ratio, and the gas-oil ratio when the formation pressure is the bubble point pressure, and the above hydrocarbon saturation of the reservoir includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation;

[0031] A third obtaining unit for judging the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir, wherein the above saturation state of the oil and gas reservoir includes a single-phase state of liquid hydrocarbon, a single-phase state of gaseous hydrocarbon, and an oil-gas miscible state;

[0032] A fourth acquisition unit, configured to obtain the hydrocarbon saturation of the reservoir based on the above-mentioned hydrocarbon reservoir saturation state, the natural gas volume under the above-mentioned surface conditions, the above-mentioned logging porosity data, and the gas-oil volume ratio data.

[0033] In a third aspect, an electronic device includes: a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program stored in the memory, the steps of the reservoir hydrocarbon saturation determination method according to any one of the first aspects described above are implemented.

[0034] In a fourth aspect, the present application further provides a computer-readable storage medium, on which a computer program is stored. When the computer program is executed by a processor, the reservoir hydrocarbon saturation determination method according to any one of the first aspects described above is implemented.

[0035] In summary, the method for determining the hydrocarbon saturation of a reservoir in the embodiments of the present application includes: obtaining gas logging data and logging porosity data; obtaining the natural gas volume and gas-oil ratio data under surface conditions based on the above gas logging data, where the above gas-oil volume ratio data includes the gas volume coefficient, the crude oil volume coefficient, the gas-oil ratio, and the gas-oil ratio when the formation pressure is the bubble point pressure, and the above reservoir hydrocarbon saturation includes at least one of the gas saturation, the oil saturation, and the total hydrocarbon saturation; judging the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir, where the above oil and gas reservoir saturation state includes the single-phase state of liquid hydrocarbons, the single-phase state of gaseous hydrocarbons, and the oil-gas miscible state; obtaining the reservoir hydrocarbon saturation based on the above oil and gas reservoir saturation state, the above natural gas volume under surface conditions, the above logging porosity data, and the above gas-oil volume ratio data. The method for determining the hydrocarbon saturation of a reservoir proposed by the present application creatively uses the calculated data of the oil reservoir physical oil and gas reservoir characteristic parameters obtained based on gas logging data, combines the reservoir porosity calculated by geophysical logging methods, and calculates the reservoir hydrocarbon saturation data. The oil and gas show data detected by gas logging comes from the true oil and gas content of the reservoir and has a good corresponding relationship with the oil and gas saturation of the reservoir. Based on the calculated hydrocarbon saturation data of the oil reservoir physical oil and gas reservoir characteristic parameters, the calculation of the liquid hydrocarbon saturation and the gaseous hydrocarbon saturation can be realized. While realizing the calculation of the hydrocarbon saturation, an accurate judgment of the natural gas type and the oil quality can be made. By using the method adopted by the present application, the formation factors affecting the resistivity will not have a decisive impact on the gas show. The hydrocarbon saturation calculated based on gas logging data is closer to the true hydrocarbon situation of the formation. By comparing the hydrocarbon saturation calculated from gas logging data with the logging hydrocarbon saturation, low-resistivity oil layers and high-resistivity water layers can be identified, and the overall recognition coincidence rate of oil and gas layers is improved. Based on the principles of reservoir physics, the present application comprehensively uses logging and logging data, and through oil reservoir physics and rock physics calculation methods, realizes the data calculation of liquid hydrocarbon saturation and gaseous hydrocarbon saturation under formation conditions, meeting the technical requirements for reservoir interpretation in the process of oil and gas exploration and development.

[0036] For the method for determining the hydrocarbon saturation of a reservoir proposed by the present application, other advantages, objectives, and features of the present application will be partially reflected by the following description, and partially will be understood by those skilled in the art through the research and practice of the present application. BRIEF DESCRIPTION OF THE DRAWINGS

[0037] By reading the following detailed description of the preferred embodiments, various other advantages and benefits will become clear to those of ordinary skill in the art. The drawings are only for the purpose of showing the preferred embodiments and are not considered to limit this specification. Moreover, throughout the drawings, the same reference numerals are used to represent the same components. In the drawings:

[0038] Figure 1Schematic flow chart of a method for determining hydrocarbon saturation in a reservoir provided by an embodiment of the present application;

[0039] Figure 2 Phase diagram of the distribution of liquid hydrocarbons and gaseous hydrocarbons in an oil and gas reservoir provided by an embodiment of the present application;

[0040] Figure 3 Schematic diagram of jointly calculating reservoir fluid saturation by gas logging and logging porosity provided by an embodiment of the present application;

[0041] Figure 4 Another schematic diagram of jointly calculating reservoir fluid saturation by gas logging and logging porosity provided by an embodiment of the present application;

[0042] Figure 5 Schematic structural diagram of a device for determining hydrocarbon saturation in a reservoir provided by an embodiment of the present application;

[0043] Figure 6 Schematic structural diagram of an electronic device for determining hydrocarbon saturation in a reservoir provided by an embodiment of the present application. Detailed implementation manners

[0044] Terms such as "first", "second", "third", "fourth", etc. (if any) in the specification, claims and above-mentioned drawings of the present application are used to distinguish similar objects, and are not necessarily used to describe a specific order or sequence. It should be understood that such used data can be interchanged under appropriate circumstances so that the embodiments described herein can be implemented in an order different from that shown or described herein. In addition, the terms "include" and "have" and any variations thereof are intended to cover non-exclusive inclusion. For example, a process, method, system, product or device that includes a series of steps or units does not necessarily have to be limited to those steps or units clearly listed, but may include other steps or units not clearly listed or inherent to these processes, methods, products or devices. The technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present application. Obviously, the described embodiments are only a part of the embodiments of the present application, rather than all of the embodiments.

[0045] The calculation of hydrocarbon saturation in oil and gas reservoirs has long been achieved based on geophysical logging data. Geophysical logging is the process of using various instruments to measure the physical parameters of underground rock formations and the technical conditions of wells during oil exploration and production, analyzing the recorded data, and conducting geological and engineering research. According to the physical basis of logging methods, there are mainly electrical logging, radioactive logging, acoustic logging, and formation dip logging, etc. In oil and gas field logging, logging data are mainly used for stratigraphic correlation, dividing oil, gas, and water layers; determining important parameters such as the porosity, oil saturation, and permeability of reservoir rocks; during the development process of oil and gas fields, studying the dynamics of oil, gas, and water and the conditions of wells, providing a basis for formulating development plans; using logging, geological, geophysical exploration, and development data to conduct comprehensive research on regional geology and reservoir description.

[0046] In the interpretation and processing of logging data, first, lithologic logging data are used to calculate the lithologic profile, obtain the shale content of the reservoir, or the volume content of other minerals, and establish the lithologic profile for logging interpretation. Secondly, based on porosity logging data and combined with data such as shale content, the porosity of the reservoir is calculated. Then, based on resistivity logging data, the Archie's formula is used to calculate the oil saturation of the reservoir.

[0047] Archie's formulas are laws regarding sandstone resistivity published by GE. Archie, a petroleum logging engineer from Shell Company in the United States in 1942. Its practical expression is:

[0048]

[0049] In the formula: a - lithology coefficient related to lithology; b - constant related to lithology; m - cementation exponent; n - saturation exponent; Rw - formation water resistivity, Ω·m; Rt - formation resistivity, Ω·m; Φ - porosity, v / v; S w — reservoir water saturation, v / v; Based on logging parameters,

[0050] The hydrocarbon saturation of the reservoir calculated using Archie's formula is: S o = 1 - S w

[0051] In the formula: S o — reservoir hydrocarbon saturation, v / v

[0052] The establishment of Archie's formula has a reliable physical basis. After 80 years of application practice, the practical value of this formula in calculating the fluid saturation of reservoirs has been verified. It is an undeniable fact that in the practice of oil and gas exploration and development, there are perceptible errors in the fluid saturation of reservoirs calculated using Archie's formula, especially in the case of low resistivity oil and gas reservoirs and high resistivity water layers, where the errors are obvious.

[0053] From the perspective of the resistivity measurement mechanism and the establishment mechanism of the Archie formula, the calculation deviation stems from whether the Archie parameters a, b, m, and n are appropriately grasped. Therefore, the difficulty in accurately calculating using the Archie formula lies in obtaining the Archie parameters of the target formation accurately. This requires a large amount of high-cost rock electricity experimental data, which is almost impossible to achieve for oil and gas exploration companies with a wide construction area. This is also a problem encountered in well logging data interpretation technology for nearly a century.

[0054] Natural gas can form reservoirs independently or coexist with crude oil. Most oil reservoirs of different properties are associated with natural gas with different characteristics, also known as associated gas.

[0055] The oil and gas detection methods in mud logging technology are an extended application of reservoir geochemistry analysis technology at the drilling construction site, and are the most timely and direct means for discovering and evaluating oil and gas reservoirs in oil and gas exploration and development.

[0056] Gas logging is a logging technology that obtains the gas carried by the drilling fluid returning from the bottom of the well, detects and records its components and total hydrocarbon content through chromatographic analysis, so as to judge the oil and gas layers, and provides basic data for the discovery and evaluation of oil and gas layers. It is one of the main means for discovering oil and gas layers.

[0057] The gas logging parameters mainly include: continuously recorded and automatically detected total hydrocarbon (TG) while drilling, hydrocarbon components (C1 (methane), C2 (ethane), C3 (propane), iC4 (isobutane), nC4 (n-butane), iC5 (isopentane) and nC5 (n-pentane)), non-hydrocarbon components (H2S (hydrogen sulfide), CO2 (carbon dioxide)), etc. logging data.

[0058] The intuitive parameter reflecting the content of associated gas is the total hydrocarbon value in the gas logging data. The net gas increment can reflect the actual gas-bearing situation of the reservoir and can be used for further calculation.

[0059] In order to quantitatively reflect the oil and gas-bearing situation of the formation, technical personnel use gas standardization calculation and try to obtain the quantitative parameter reflecting the oil and gas-bearing situation of the formation, the ground gas content, through calibration methods.

[0060] The ground gas content is the volume of gas released per unit volume of rock drilled under ground conditions. The change in the gas volume of breaking unit volume of rock reflects the change in the relative porosity of the rock and the change in the gas saturation in the rock.

[0061] The theoretical basis of the ground gas content interpretation method is: it is assumed that the natural gas value of the known display section is directly related to the broken rock volume of this display section. When drilling through two completely identical reservoirs, due to differences in drilling speed, drilling fluid displacement, and bit diameter (excluding uncontrollable factors), there will be significant differences in hydrocarbon shows. The key to the formation gas content chart interpretation method is to standardize the hydrocarbon shows, eliminate the influence of factors such as drilling time, bit, and drilling fluid displacement, and calculate the formation gas content. Therefore, through continuous calculation, the changes in gas content at different depths in the same well can be compared, and oil, gas, and water layers can be judged.

[0062] Through theoretical calculation, the gas content in the drilling fluid detected by surface instruments is converted into the ground gas content of the rock, providing a quantitative parameter for judging reservoir properties. The NTC calculation derivation comes from the "Field Technical Specification for Exploration and Production Engineering Supervision of PetroChina Company Limited - Geological Supervision Sub - volume" compiled by PetroChina Company Limited. After considering unit conversion:

[0063]

[0064] In the formula: TC - the sum of the concentrations of each component, % or 10 -6 ; Q - the outlet displacement of the drilling fluid, m 3 / min; ROP - drilling time, min / m; d - the outer diameter of the bit, mm; k - the correction value of the degassing efficiency of the degasser, and currently the degassing efficiency can reach 0.75; NTC - under surface conditions, the gas volume content per unit volume of rock, with the same unit as TC.

[0065] NTC is the theoretical ground gas content calculated by eliminating common influencing factors through gas detection values, and is also called the Gas Normalization value. When using TG instead of TC for calculation, the calculation result is called NTG. Since the calculation formulas of NTC and NTG contain ROP, in tight formation sections, a high ROP leads to a high NTC (NTG) value, and this value is not caused by the formation hydrocarbon content at this time. Therefore, constraints need to be placed on the use of NTC (NTG). Practice has proved that NTC (NTG) can solve the problem of quantitative calculation to a certain extent, but there are still many unsatisfactory situations in its application.

[0066] For gas normalization calculation, in 2017, Zhang Guodong published a paper titled "Discriminating the Gas - bearing Property of Low - Porosity and Low - Permeability Reservoirs by the Full - Quantity Forward Calculation Method of Gas Logging" based on the working mechanism of a quantitative degasser, reaching a new height. The gas normalization calculation formula given in the paper is:

[0067]

[0068] Where: r - wellbore radius, m; v0 - penetration rate, m / min; t - drilling time, min; Φ - rock porosity, %; Sg - gas saturation of crushed rock, %; Punderground - pore pressure of the drilled formation, Pa; Tunderground - temperature of the drilled formation, K, which can be obtained based on the geothermal gradient; Psurface - surface atmospheric pressure, Pa; Tsurface drilling fluid - temperature of the drilling fluid in the degassing tank, 343.15 K; Fflow - drilling fluid flow rate, m3 / min; 300 - volume of drilling fluid obtained per degassing, 300 cm3; 500 - flow rate of the degassing pipeline, 500 cm3 / min; Tg calculated - concentration of hydrocarbons in the sample gas pipeline, %; By equating Tg calculated with the total hydrocarbon value of gas logging, the gas saturation value of the reservoir can be obtained:

[0069]

[0070] There is no problem with the logical deduction of this calculation formula. The problem is that the penetration rate v0 used in it is an engineering construction parameter, and t is the drilling time. Although they are quantitatively expressed parameters, their essence is still qualitative parameters affected by construction factors and not real rock physical parameters; mixing with gas physical parameters and rock physical parameters such as temperature, pressure, and porosity that are not affected by engineering factors leads to distortion of the final calculation result.

[0071] What reflects the characteristics of the oil and gas reservoir is the ratio of gas components, and many effective methods have emerged in production practice. For oil and gas reservoirs with different crude oil properties, the associated gas component ratios such as the Pick's ratio, triangular plot index, comprehensive gas index, etc. have different characteristics. Conversely, through the characteristics of the gas component ratio, the characteristics of the underground oil and gas reservoir can be inferred to judge dry gas, wet gas, light oil, medium oil, heavy oil, etc. The characteristics of the oil and gas reservoir can be quantitatively expressed by the gas component ratio. For oil and gas reservoirs with different crude oil properties, their gas-oil ratios vary greatly, and the characteristics of the oil and gas reservoir can be reflected through the gas-oil ratio data. The gas-oil ratio (GOR) is one of the important characteristic parameters of the oil and gas reservoir, and its value can be calculated and obtained through an empirical equation based on gas logging data and regional oil and gas well test production data. Other oil and gas reservoir parameters such as natural gas relative density, crude oil density, viscosity, etc. can be quantitatively calculated through a series of logical inferences and data regression processing. In the exploration and evaluation stage of the oil and gas reservoir, the characteristic parameters of the associated gas of the oil and gas reservoir can be calculated based on gas logging data and corrected through oil and gas well test and production data, which has practical application value and lays a foundation for the quantitative calculation and evaluation of the oil and gas content of the reservoir.

[0072] The present invention relates to the technical field of oil and gas exploration and development data processing, and particularly relates to using gas logging data and porosity logging data, and based on oil and gas reservoir characteristic parameters and the well sections with oil and gas shows distribution, adopting computer processing technology to obtain the oil and gas saturation of the oil and gas reservoir.

[0073] To solve some of the problems existing in the prior art, please refer to Figure 1 , which is a schematic flow chart of a method for determining the hydrocarbon saturation of a reservoir provided by an embodiment of the present application, and specifically may include:

[0074] S110. Obtain gas logging data and log porosity data;

[0075] Exemplarily, the oil and gas show data detected by gas logging originates from the actual hydrocarbon content of the reservoir, and has a good corresponding relationship with the hydrocarbon saturation of the reservoir. Based on the calculation of hydrocarbon saturation data based on the physical characteristics of the oil reservoir, the calculation of liquid hydrocarbon saturation and gaseous hydrocarbon saturation can be realized. While realizing the calculation of hydrocarbon saturation, accurate judgments can be made on the type of natural gas and the quality of the oil.

[0076] Log porosity is an important concept in geology and petroleum engineering, which describes the proportion of voids or pores in rocks or reservoirs. Porosity is usually expressed as a percentage, indicating the percentage of voids in the rock or reservoir in the total volume.

[0077] S120. Based on the above gas logging data, obtain the natural gas volume and gas-oil ratio data under surface conditions, where the above gas-oil volume ratio data includes gas volume coefficient, crude oil volume coefficient, gas-oil ratio, and gas-oil ratio when the formation pressure is the bubble point pressure, and the above reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation;

[0078] Exemplarily, according to the basic principle of gas temperature and pressure calculation, the natural gas from the reservoir returns to the surface with the drilling fluid. Before entering the chromatographic column, there are three temperature and pressure environments: formation environment, wellhead degasser environment, and sample gas pipeline environment, and their temperature, pressure, and volume satisfy specific gas equations. Based on the gas detection and analysis data, the temperature and pressure conditions of the sample gas, surface, and outlet drilling fluid, the natural gas volume under surface conditions can be deduced. Among them, the above gas-oil volume ratio data includes gas volume coefficient, crude oil volume coefficient, gas-oil ratio, and gas-oil ratio when the formation pressure is the bubble point pressure, and the above reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation

[0079] S130. Obtain the saturated state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir, where the above saturated state of the oil and gas reservoir includes a single-phase state of liquid hydrocarbon, a single-phase state of gaseous hydrocarbon, and a miscible state of oil and gas;

[0080] Exemplarily, the saturation states of the oil and gas reservoir include the single-phase state of liquid hydrocarbons, the single-phase state of gaseous hydrocarbons, and the miscible state of oil and gas. The single-phase state of liquid hydrocarbons means that the gas phase is completely dissolved in the liquid phase, the single-phase state of gaseous hydrocarbons means that the liquid phase is completely dissolved in the gas phase, and the miscible state of oil and gas is a mixed state of the gas phase and the liquid phase. When the formation pressure is greater than the bubble point pressure of the above-mentioned oil reservoir, the saturation state of the above-mentioned oil and gas reservoir is the above-mentioned single-phase state of liquid hydrocarbons or the above-mentioned single-phase state of gaseous hydrocarbons; when the above-mentioned formation pressure is less than the bubble point pressure of the above-mentioned oil reservoir, the saturation state of the above-mentioned oil and gas reservoir is the above-mentioned miscible state of oil and gas.

[0081] S140. Obtain the hydrocarbon saturation of the reservoir based on the above-mentioned saturation state of the oil and gas reservoir, the volume of natural gas under the above-mentioned surface conditions, the above-mentioned log porosity data, and the gas-oil volume ratio data.

[0082] Exemplarily, after calculating the volume of natural gas under surface conditions, select the corresponding calculation formula to calculate the hydrocarbon saturation of the reservoir according to different saturation states of the oil and gas reservoir. The calculation formula is related to the volume of natural gas, porosity data, and gasoline volume ratio data. Among them, the gas-oil volume ratio data includes the gas volume factor, the crude oil volume factor, the gas-oil ratio, and the gas-oil ratio when the formation pressure is the bubble point pressure. The above-mentioned hydrocarbon saturation of the reservoir includes at least one of the gas saturation, the oil saturation, and the total hydrocarbon saturation.

[0083] In summary, the method for determining the hydrocarbon saturation of the reservoir proposed in this application creatively uses the calculation data of the oil reservoir physical oil and gas reservoir characteristic parameters obtained based on gas logging data, combines the porosity of the reservoir calculated by geophysical logging methods, and calculates the hydrocarbon saturation data of the reservoir. The oil and gas show data detected by gas logging comes from the true hydrocarbon content of the reservoir, and has a good corresponding relationship with the hydrocarbon saturation of the reservoir. Based on the calculated hydrocarbon saturation data of the oil reservoir physical oil and gas reservoir characteristic parameters, the calculation of the liquid hydrocarbon saturation and the gaseous hydrocarbon saturation can be realized. While realizing the calculation of the hydrocarbon saturation, the type of natural gas and the oil quality can be accurately judged. Using the method adopted in this application, the formation factors affecting the resistivity will not have a decisive impact on the gas show. The hydrocarbon saturation calculated based on gas logging data is closer to the true hydrocarbon situation of the formation. Comparing the hydrocarbon saturation calculated from gas logging data with the log hydrocarbon saturation can identify low-resistivity oil layers and high-resistivity water layers, and overall improve the identification coincidence rate of oil and gas layers. Based on the oil reservoir physical principle, this application comprehensively uses logging and logging data, and through oil reservoir physical and rock physical calculation methods, realizes the data calculation of liquid hydrocarbon saturation and gaseous hydrocarbon saturation under formation conditions, meeting the technical requirements for reservoir interpretation in the process of oil and gas exploration and development.

[0084] In one embodiment, the above gas logging data includes a degassing efficiency correction coefficient, the chromatograph sample gas flow rate, the net gas increment in the outlet drilling fluid, the sample gas pipeline pressure, the drilling fluid outlet temperature, the drilling fluid outlet flow rate, the surface temperature, the surface pressure, and the flow rate of the degasser sucking the drilling fluid.

[0085] Obtaining the natural gas volume and gas-oil ratio data under surface conditions based on the above gas logging data includes:

[0086] Obtaining the natural gas volume under the above surface conditions based on the above degassing efficiency correction coefficient, the above chromatograph sample gas flow rate, the above net gas increment in the outlet drilling fluid, the above sample gas pipeline pressure, the above drilling fluid outlet temperature, the drilling fluid outlet flow rate, the above surface temperature, the above surface pressure, and the flow rate of the degasser sucking the drilling fluid.

[0087] Exemplarily, according to the basic principle of gas temperature and pressure calculation, the natural gas from the reservoir returns to the surface with the drilling fluid. Before entering the chromatographic column, there are three temperature and pressure environments: the formation environment, the wellhead degasser environment, and the sample gas pipeline environment. The gas equations for their temperature, pressure, and volume are:

[0088]

[0089] Based on the gas detection and analysis data, the temperature and pressure conditions of the sample gas, the surface, and the outlet drilling fluid, the natural gas volume under the surface conditions can be deduced. Specifically, the natural gas volume under the surface conditions can be obtained through the degassing efficiency correction coefficient, the chromatograph sample gas flow rate, the net gas increment in the outlet drilling fluid, the sample gas pipeline pressure, the drilling fluid outlet temperature, the drilling fluid outlet flow rate, the surface temperature, the surface pressure, and the flow rate of the degasser sucking the drilling fluid.

[0090] In one embodiment, the above method further includes:

[0091] Determining the natural gas volume GSS under the above surface conditions based on the following formula:

[0092]

[0093] In the formula, k is the above degassing efficiency correction coefficient, Q is the above chromatograph sample gas flow rate, DTC is the above net gas increment in the outlet drilling fluid, P tube is the above sample gas pipeline pressure, T out is the above drilling fluid outlet temperature, Flrate is the above drilling fluid outlet flow rate, T S is the above surface temperature, P S is the above surface pressure, Q d is the above flow rate of the degasser sucking the drilling fluid.

[0094] In one embodiment, obtaining the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the reservoir includes:

[0095] When the formation pressure is greater than the bubble point pressure of the reservoir, the saturation state of the oil and gas reservoir is the single-phase state of the liquid hydrocarbon or the single-phase state of the gaseous hydrocarbon; and / or

[0096] When the formation pressure is less than the bubble point pressure of the reservoir, the saturation state of the oil and gas reservoir is the oil-gas miscible state.

[0097] Exemplarily, the bubble point pressure of the reservoir can be calculated using the empirical relationship proposed by Glaso:

[0098]

[0099] Wherein,

[0100]

[0101] In the formula: P b —Bubble point (dew point) pressure of the oil and gas reservoir, MPa;

[0102] In one embodiment, obtaining the hydrocarbon saturation of the reservoir based on the saturation state of the oil and gas reservoir, the natural gas volume under the surface conditions, the logging porosity data, and the gas-oil volume ratio data corresponds to the following three saturation states of the oil and gas reservoir:

[0103] The first saturation state of the oil and gas reservoir: When the saturation state of the oil and gas reservoir is the single-phase state of the gaseous hydrocarbon, the gas saturation is determined according to the gas volume coefficient, the natural gas volume under the surface conditions, and the logging porosity data.

[0104] Exemplarily, when the saturation state of the oil and gas reservoir is the single-phase state of the gaseous hydrocarbon, the gas saturation Sg is:

[0105]

[0106] Wherein, B g Is the gas volume coefficient, GSS is the natural gas volume under the surface conditions, and POR is the logging porosity data

[0107] The second saturation state of the oil and gas reservoir: When the saturation state of the oil and gas reservoir is the single-phase state of the liquid hydrocarbon, the oil saturation is determined according to the crude oil volume coefficient, the natural gas volume under the surface conditions, the gas-oil ratio, and the logging porosity data.

[0108] Exemplarily, when the saturation state of the oil and gas reservoir is the single-phase state of the liquid hydrocarbon, the oil saturation SO is:

[0109]

[0110] Among them, B o is the formation volume factor of crude oil, GSS is the volume of natural gas under surface conditions, GOR is the gas-oil ratio, and POR is the log porosity data.

[0111] The third type of hydrocarbon reservoir saturation state: In the case where the above hydrocarbon reservoir saturation state is the above hydrocarbon miscible state, determine the gas saturation according to the gas-oil ratio when the above formation pressure is the bubble point pressure, the above oil-gas ratio, the above gas volume factor, the above formation volume factor of crude oil, the above volume of natural gas under surface conditions, and the above log porosity data;

[0112] Determine the oil saturation according to the above formation volume factor of crude oil, the above volume of natural gas under surface conditions, the above gas-oil ratio, and the above log porosity data;

[0113] Determine the total hydrocarbon saturation according to the gas-oil ratio when the above formation pressure is the bubble point pressure, the above oil-gas ratio, the above gas volume factor, the above formation volume factor of crude oil, the above volume of natural gas under surface conditions, and the above log porosity data.

[0114] Exemplarily, in the case where the above hydrocarbon reservoir saturation state is the above hydrocarbon miscible state, the gas saturation Sg is:

[0115]

[0116] The oil saturation S O :

[0117]

[0118] The total hydrocarbon saturation S go :

[0119]

[0120] The water saturation is

[0121] S w = 1 - S go

[0122] The reservoir space fluid volume ratio model is:

[0123] Gas phase volume: POR gas = POR × S g

[0124] Oil phase volume: POR o = POR × S o

[0125] Total oil and gas volume: POR go = Sg +S o

[0126] Volume of bound water: POR Swi = POR × S wi

[0127] Volume of movable water: PORS mw = POR ― PORS wi ― POR gas ― POR o

[0128] Total volume of water: POR w = POR mw + POR Swi

[0129] The fluid volume filling model of reservoir storage space is:

[0130] POR Swi = POR × S wi

[0131] POR w = PORS wi + POR mw

[0132] POR wo = POR w + POR o

[0133] POR wog = POR w + POR o + POR gas

[0134] POR = POR Swi + POR mw + POR gas + POR o

[0135] In the above calculation process, the parameters that may be used are calculated by the following method.

[0136] The formation pressure is:

[0137] Pf = 9.8 × 10 -3 · FP · TVD

[0138] Where: Pf — formation pressure, MPa; TVD — true vertical depth, m; FP — formation pressure coefficient.

[0139] The formation temperature is:

[0140] T f= G • TVD + α

[0141] Where: T f —Geothermal temperature, °C; TVD—True vertical depth, m; G—Geothermal gradient, °C / 100m; α—Average temperature of the constant temperature zone in the work area, 23 °C can be used for reference in new exploration areas.

[0142] Natural gas is a mixture and has no constant molecular weight. Its molecular weight can be calculated based on gas logging data according to the key rule to obtain the relative density Mg of natural gas:

[0143] M g = ∑y i M i

[0144] Where: M g —Average molecular weight of natural gas; Y i —Mole fraction of component i in natural gas; M i —Molecular weight of component i in natural gas

[0145] If both natural gas and air are at the same standard state, the relative density γ of natural gas g can be expressed by the following formula:

[0146]

[0147] Where: γ g —Relative density of natural gas; ρ g —Density of natural gas; ρ air —Density of air; Mg—Molecular weight of natural gas; Mair—Molecular weight of air; Under standard temperature (293K or 20 °C) and standard pressure (0.101 MPa), the air density is 1.205 g / L.

[0148] The Winn-Sim-Daubert (1980) formula is used to calculate the critical pressure P c and critical temperature Tc

[0149]

[0150]

[0151] Where: T c —Critical temperature of the true boiling point fraction, K; p c —Critical pressure of the true boiling point fraction, MPa; T b —Boiling point of the true boiling point fraction, K; γ—Relative density of the true boiling point fraction.

[0152]

[0153] Table 1 Critical Parameters of Common Natural Gas Components

[0154] Calculation of pseudo-critical pressure:

[0155] p pc =∑y i p ci

[0156] Calculation of pseudo-critical temperature:

[0157] T pc =∑y i T ci

[0158] Where: y i —Mole or volume fraction of component i in natural gas components; P ci —Critical pressure of component i, MPa; T ci —Critical temperature of component i, K; P pc —Pseudo-critical pressure of component i, MPa; T pc —Pseudo-critical temperature of component i, K;

[0159] Calculation of pseudo-reduced parameters of natural gas:

[0160]

[0161]

[0162] Where: p pr —Pseudo-reduced pressure (also marked as P r ); T pr —Pseudo-reduced temperature (also marked as T r ).

[0163] Standing and Katz published a chart of natural gas deviation factors in 1941, which reflects the relationship curves between natural gas deviation factors and pressure and temperature. The application conditions are in the range of 0.2 ≤ P pr ≤ 15 and 1.05 ≤ T pr ≤ 3.0. Currently, the commonly used calculation models of natural gas deviation factors are all obtained by fitting the above curves. Only the methods used are different, resulting in different application conditions and calculation accuracies.

[0164] Professor Li Xiangfang re-optimized the curve fitting method and simultaneously fitted the natural gas deviation factor in the full temperature and full pressure ranges, establishing a high-precision analytical calculation model for natural gas deviation factors. The natural gas deviation factor can be calculated with reference to the analytical calculation model of natural gas deviation factors after Professor Li Xiangfang re-optimized the curve fitting method.

[0165] Gas volume factor B gCalculated by the following formula:

[0166]

[0167] In the formula: P sc — The pressure of natural gas under standard conditions, MPa; Tsc — The temperature of natural gas under standard conditions, K; Z — The deviation coefficient of natural gas. China's "Standard Orifice Plate Calculation Method for Natural Gas Flow" stipulates that the standard state for measuring the volume flow of gas is a temperature of 293.15 K (20 °C) and a pressure of 101.325 KPa.

[0168] For the calculation of gas-oil ratio, the empirical equation method of gas parameters can be used to obtain the empirical relationship proposed by Glaso based on the statistical analysis results of oil and gas reservoir samples in the North Sea region:

[0169]

[0170] Where:

[0171] C = 2.8869 ― [14.1811 ― 3.3093 · log(145.04 · P)] 0.5

[0172] In the formula: R s — Gas-oil ratio, m3 / m3; γ g — Relative density of natural gas; γ O — Density of crude oil, g / cm3; T — Reservoir temperature, K;

[0173] In recent years, with the progress of technical research, other empirical formulas in the practice of calculating gas-oil ratio based on the empirical equation fitted from gas logging data can also be used.

[0174] When calculating the bubble point pressure (P = P b ), the gas-oil ratio value is adopted as:

[0175]

[0176] Where:

[0177] C = 2.8869 ― [14.1811 ― 3.3093 · log(145.04 · P b )] 0.5

[0178] In the formula:

[0179] R SB — The gas-oil ratio value when the formation pressure is the bubble point pressure, m3 / m3; P b — Bubble point (dew point) pressure of the oil and gas reservoir, MPa;

[0180] The volume coefficient B0 adopts the empirical relationship proposed by Standing:

[0181] B O = 0.972 + 0.01213×D 1.175

[0182] Wherein,

[0183] In the formula: B O - Formation oil volume coefficient. Based on the "Prediction Model of Dissolved Gas Oil Volume Coefficient and Density" by Lu Shuangfang et al., according to the fact that the formation oil mass is equal to the sum of the surface oil and the released gas mass, the empirical relationship is proposed:

[0184]

[0185] In the formula:

[0186] d of - Formation oil density, g / cm 3

[0187] According to the well testing data of Zhongyuan Oilfield, through the statistical regression between the produced gas-oil ratio and the surface oil density data, the empirical formula between the density and the gas-oil ratio is obtained:

[0188]

[0189] In the formula: c - Regional empirical coefficient, preferably 0.9694; d - Regional empirical coefficient, preferably -0.028; Rs - Produced gas-oil ratio, m 3 / m 3 ; γ o - Surface oil density, g / cm 3

[0190] The common formula for calculating shale content using natural gamma (GR) logging data:

[0191]

[0192] In the formula: SH - Relative value of natural gamma; GR - Natural gamma logging value of the target layer; GRmin - Natural gamma logging value of the pure lithology formation; GRmax - Natural gamma logging value of the pure shale formation.

[0193]

[0194] In the formula, Vsh - Shale content, decimal; GCUR - Empirical coefficient related to the formation age, take 3.7 for new formations and 2 for old formations.

[0195] The calculation methods of porosity from well logging data include those using acoustic transit time, density logging, and compensated neutron logging data, etc.

[0196] When calculating porosity using acoustic transit time, the formula for calculating porosity from acoustic transit time data is:

[0197]

[0198] Where: Φs - porosity calculated by acoustic wave, in decimal; DTma, DTf - acoustic transit times of rock matrix and formation fluid respectively, in μs / m; Vsh - shale content of the formation, in decimal; CP - acoustic wave compaction correction coefficient, which can be obtained by statistical calculation of core analysis porosity and acoustic wave calculated porosity, or by statistical calculation of density porosity and acoustic wave porosity. DT - acoustic transit time log value of the target layer, in μs / m.

[0199] Calculating porosity based on density logging data

[0200]

[0201] Where: Φ D - density porosity, in decimal; D ma , D f - density values of rock matrix and formation fluid respectively, in g / cm 3 ; DEN - density log value of the target layer, in g / cm3; D sh - density value of shale, in g / cm3; V sh - shale content of the reservoir, in decimal.

[0202] Calculating porosity through compensated neutron logging data:

[0203] ΦN = (CN - LCOR - 0.5 × Vsh × Nsh) × 0.01

[0204] Where: Φ N - neutron porosity, in decimal; CN - compensated neutron log value of the target layer, in %; LCOR - neutron value of rock matrix, in %; Vsh - shale content of the target layer, in decimal; Nsh - neutron value of shale, in %.

[0205] An empirical calculation formula for irreducible water saturation is established based on porosity, shale content, and wettability:

[0206]

[0207] The a, b, and c in the formula are statistical empirical coefficients related to lithology. The recommended expression given by Professor Yong Shihe in "Well Logging Data Processing and Comprehensive Interpretation" is:

[0208]

[0209] When it is the case that When the calculated result Swi ≤ 0.15, take Swi = 0.15.

[0210] After there are sufficient analysis data in the exploration work area, an empirical calculation formula for irreducible water saturation of this work area can be established.

[0211] The volume of the rock occupied by irreducible water in the reservoir is:

[0212] POR swi = POR × S wi

[0213] The volume of the effective reservoir space in the reservoir is:

[0214] PORA = POR ― POR swi

[0215] In the formula: PORA—the volume of the effective reservoir space in the reservoir; POR Swi —the volume of the rock occupied by irreducible water in the reservoir; PORA is the volume of the effective reservoir space in the reservoir.

[0216] When balanced drilling is carried out, the natural gas and crude oil contained in the reservoir will enter the drilling fluid along with the cuttings broken by the drill bit and be carried to the wellhead. The sum of the volumes of the crude oil and natural gas should be equal to the value of PORA.

[0217] When underbalanced drilling is carried out, formation fluids will enter the wellbore. At this time, the sum of the volumes of the crude oil and natural gas carried to the wellhead will be greater than the value of PORA.

[0218] When overbalanced drilling is carried out, wellbore fluids will enter the formation. At this time, the sum of the volumes of the crude oil and natural gas carried to the wellhead will be less than the value of PORA.

[0219] When calculating hydrocarbon saturation by jointly using logging - well logging data, the sum of gas components is TC:

[0220] TC = C1 + C2 + C3 + iC4 + nC4 + iC5 + nC5

[0221] DTC = TC - TCBK

[0222] In the formula: DTC—the net value data of component sum, %; TCBK—the baseline value of the component sum curve, %.

[0223] Or:

[0224] DTG = TG - TGBK

[0225] Where: DTG--Net total hydrocarbon data, %; TG--Detected total hydrocarbon value, %; TGBK--Total hydrocarbon curve baseline value, %.

[0226] Based on the calculation method of gas-oil ratio, the volume of surface crude oil is:

[0227]

[0228] Where: Vos—Volume of crude oil returned to the surface with drilling fluid, m 3 ; GOR—Gas-oil ratio, m 3 / m 3 ;

[0229] The volume of formation gas is:

[0230] G f =B g ×GSS

[0231] Where G f —Volume of gas under formation temperature and pressure conditions, m 3 ;

[0232] The volume of formation crude oil is:

[0233] V of =B o ×V os

[0234] Where: V of —Volume of crude oil under formation temperature and pressure conditions, m 3 ;

[0235] The volume of gas and the total volume of crude oil under formation conditions are:

[0236] V gof =G f +V os

[0237] Where: V gof —Single-phase state of the total gas and crude oil under formation temperature and pressure conditions.

[0238] When the reservoir fluid property is in a single-phase gaseous state, the gas saturation of the reservoir:

[0239]

[0240] When the reservoir fluid property is in a single-phase liquid state, the oil saturation of the reservoir:

[0241]

[0242] Where: POR—Reservoir porosity, v / v;

[0243] When the formation pressure is less than the bubble point pressure of the reservoir, the reservoir fluid is in a gas-liquid hydrocarbon miscible state of liquid hydrocarbons and gaseous hydrocarbons. A part of the gaseous hydrocarbons is dissolved in the liquid crude oil, and a part exists in the reservoir in a gaseous state.

[0244] Under the temperature and pressure conditions of the reservoir, the schematic diagram of the liquid-gas ratio in the reservoir is as Figure 2 shown.

[0245] The gas-oil ratio on the bubble point (dew point) line of the reservoir is RSB, and the gas-oil ratio (GOR, Gas Oil Ratio) of the reservoir is RS.

[0246] In the two-phase region, the value of the free-phase gas is:

[0247] GORF = (R SB ―R S )·B g

[0248] Where: GORF—the volume ratio of gaseous hydrocarbons to liquid hydrocarbons in the two-phase region, m3 / m3 R S —gas-oil ratio product, m 3 ;

[0249] When the formation pressure is greater than the bubble point pressure of the reservoir, the reservoir fluid is liquid hydrocarbons or gaseous hydrocarbons

[0250] (GOR), m3 / m3

[0251] Volume ratio of formation gas phase to liquid hydrocarbons

[0252]

[0253] Volume of formation gaseous hydrocarbons:

[0254] V gf = GORF × V of

[0255] Gas phase saturation:

[0256]

[0257]

[0258] Liquid phase hydrocarbon saturation

[0259]

[0260] Total hydrocarbon saturation

[0261]

[0262]

[0263] In one embodiment, the calculation method of the present invention creatively uses the calculation data of the physical characteristics of oil and gas reservoirs in the oil layer, based on the net gas increment data of gas logging data, and cooperates with the reservoir log porosity data calculated by geophysical logging methods to calculate and obtain the gas saturation, oil saturation and total oil and gas saturation of the oil and gas reservoir. The quantity distribution of pore fluids can be displayed in the form of numerical tables and curves, providing a basic method for fine interpretation of reservoir fluid properties.

[0264] Calculations of logging-logging oil and gas saturation were carried out on sandstone oil and gas reservoirs in the Chad exploration area of Africa. The schematic diagram of the results is as Figure 3 shown. Through calculation, the oil and gas saturation of the reservoir, as well as the volume values of liquid oil, gaseous hydrocarbons and water in the pores of the reservoir, POR o 、POR g and POR w were obtained. On the cross-section, the occurrence states of oil, gas and water in the reservoir are intuitively displayed. In Figure 3 , the gas logging data include: C1 - methane, 10 -6 ; C2 - ethane, 10 -6 ; C3 - propane, 10 -6 ; iC4 - isobutane, 10 -6 ; nC4 - normal butane, 10 -6 ; iC5 - isopentane, 10 -6 ; nC5 - normal pentane, 10 -6 ; TG - total hydrocarbon, 10 -6 ; The logging parameters include: BS - bit size, mm; CAL - borehole diameter, mm; GR - natural gamma, API; SP - spontaneous potential, mV; RHOB - density logging, g / cm 3 ; NPHI - neutron logging, v / v; DT - acoustic travel time, μs / m; VSH - shale content, v / v; PHIE - porosity, v / v; ML_RESULT - logging interpretation conclusion; WL_RESULT - logging interpretation conclusion; TEST_RESULT - oil testing conclusion.

[0265] In carbonate reservoirs and sandstone reservoirs, the technical method of the present invention has been applied and has achieved good verification results. In the oil and gas field K13 in the Chad exploration area of Africa, good oil and gas shows were encountered in the sandstone reservoir. Based on the characteristics of gas logging data, the physical characteristics parameters of the reservoir oil layer were calculated, combined with the logging porosity data of geophysical logging, and the hydrocarbon saturation data was calculated. The calculation results are as Figure 4As shown in the figure. In Well K13, according to the logging data, the interval from 2001.30 m to 2009.38 m is interpreted as an oil layer based on the logging data, and as a gas layer based on the gas logging ratio characteristics. According to the physical characteristic parameters of the reservoir oil layer, the gas saturation and oil saturation are calculated respectively. Based on the calculation results, it is judged that the interval from 2001.30 m to 2009.38 m is mainly gas-bearing and contains less liquid hydrocarbons. In the subsequent well testing operation, after perforating the interval from 2001.30 m to 2009.38 m, a 32 / 64 in choke is used, and the natural gas production is 253070 m 3 / d, and the liquid oil is not measured. The well testing results are consistent with the conclusions obtained by using the calculation method of the present invention.

[0266] Please refer to Figure 5 , an embodiment of the device for determining the hydrocarbon saturation of a reservoir in an embodiment of the present application may include:

[0267] A first acquisition unit 21, configured to acquire gas logging data and logging porosity data;

[0268] A second acquisition unit 22, configured to acquire the volume of natural gas and the gas-oil ratio data under surface conditions based on the above gas logging data, wherein the above gas-oil volume ratio data includes the gas volume coefficient, the crude oil volume coefficient, the gas-oil ratio, and the gas-oil ratio when the formation pressure is the bubble point pressure, and the above hydrocarbon saturation of the reservoir includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation;;

[0269] A third acquisition unit 23, configured to acquire the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir, wherein the above saturation state of the oil and gas reservoir includes a single-phase state of liquid hydrocarbons, a single-phase state of gaseous hydrocarbons, and a miscible state of oil and gas;

[0270] A fourth acquisition unit 24, configured to acquire the hydrocarbon saturation of the reservoir based on the above saturation state of the oil and gas reservoir, the above volume of natural gas under surface conditions, the above logging porosity data, and the gas-oil volume ratio data.

[0271] As Figure 6 shown, an embodiment of the present application further provides an electronic device 300, including a memory 310, a processor 320, and a computer program 311 stored in the memory 310 and executable on the processor. When the processor 320 executes the computer program 311, the steps of any of the above methods for determining the hydrocarbon saturation of the reservoir are implemented.

[0272] Since the electronic device introduced in this embodiment is the device adopted for implementing a reservoir hydrocarbon saturation determination device in an embodiment of the present application, based on the method introduced in the embodiment of the present application, those skilled in the art can understand the specific implementation manners and various variations of the electronic device in this embodiment. Therefore, the specific implementation of how this electronic device implements the method in the embodiment of the present application will not be described in detail here. As long as the device adopted by those skilled in the art to implement the method in the embodiment of the present application falls within the scope of protection of the present application.

[0273] In the specific implementation process, when the computer program 311 is executed by the processor, it can implement Figure 1 any one of the implementation manners in the corresponding embodiment.

[0274] It should be noted that in the above embodiments, the descriptions of each embodiment have their own emphases. For the parts not described in detail in a certain embodiment, reference can be made to the relevant descriptions of other embodiments.

[0275] The above, the above embodiments are only used to illustrate the technical solutions of the present application, rather than to limit them; although the present application has been described in detail with reference to the foregoing embodiments, those of ordinary skill in the art should understand that they can still modify the technical solutions recorded in the foregoing embodiments, or perform equivalent replacements on some of the technical features; and these modifications or replacements do not make the essence of the corresponding technical solutions deviate from the spirit and scope of the technical solutions of the embodiments of the present application.

Claims

1. A method for determining hydrocarbon saturation in a logging and well testing reservoir, characterized in that, it includes: Obtaining gas logging data and logging porosity data; Obtaining the natural gas volume and gas-oil ratio data under surface conditions based on the gas logging data, wherein the gas-oil volume ratio data includes gas volume coefficient, crude oil volume coefficient, gas-oil ratio, and gas-oil ratio when the formation pressure is the bubble point pressure, and the hydrocarbon saturation in the reservoir includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation; Judging the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir, wherein the saturation state of the oil and gas reservoir includes a single-phase state of liquid hydrocarbon, a single-phase state of gaseous hydrocarbon, and an oil-gas miscible state; Obtaining the hydrocarbon saturation in the reservoir based on the saturation state of the oil and gas reservoir, the natural gas volume under surface conditions, the logging porosity data, and the gas-oil volume ratio data.

2. The method for determining hydrocarbon saturation in a reservoir according to claim 1, characterized in that, the gas logging data includes degassing efficiency correction coefficient, chromatograph sample gas flow rate, net gas increment in the outlet drilling fluid, sample gas pipeline pressure, drilling fluid outlet temperature, drilling fluid outlet flow rate, surface temperature, surface pressure, and flow rate of the degasser sucking the drilling fluid, the obtaining the natural gas volume and gas-oil ratio data under surface conditions based on the gas logging data includes: Obtaining the natural gas volume under surface conditions based on the degassing efficiency correction coefficient, the chromatograph sample gas flow rate, the net gas increment in the outlet drilling fluid, the sample gas pipeline pressure, the drilling fluid outlet temperature, the drilling fluid outlet flow rate, the surface temperature, the surface pressure, and the flow rate of the degasser sucking the drilling fluid.

3. The method for determining hydrocarbon saturation in a reservoir according to claim 2, characterized in that, it further includes: Determining the natural gas volume GSS under surface conditions based on the following formula: Wherein, k is the degassing efficiency correction coefficient, Q is the chromatograph sample gas flow rate, DTC is the net gas increment in the outlet drilling fluid, P tube is the sample gas pipeline pressure, T out is the drilling fluid outlet temperature, Flrate is the drilling fluid outlet flow rate, T S is the surface temperature, P S is the surface pressure, Q d is the flow rate of the degasser to draw the drilling fluid.

4. The method for determining hydrocarbon saturation in a reservoir according to claim 1, characterized in that, judging the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir includes: When the formation pressure is greater than the bubble point pressure of the oil reservoir, the saturation state of the oil and gas reservoir is the single-phase state of liquid hydrocarbon or the single-phase state of gaseous hydrocarbon; and / or When the formation pressure is less than the bubble point pressure of the oil reservoir, the saturation state of the oil and gas reservoir is the oil-gas miscible state.

5. The method for determining hydrocarbon saturation in a reservoir according to claim 1, characterized in that, the obtaining the hydrocarbon saturation in the reservoir based on the saturation state of the oil and gas reservoir, the natural gas volume under surface conditions, the logging porosity data, and the gas-oil volume ratio data includes: When the saturation state of the oil and gas reservoir is the single-phase state of gaseous hydrocarbon, determining the gas saturation according to the gas volume coefficient, the natural gas volume under surface conditions, and the logging porosity data.

6. The method for determining hydrocarbon saturation in a reservoir according to claim 1, characterized in that, the obtaining the hydrocarbon saturation in the reservoir based on the saturation state of the oil and gas reservoir, the natural gas volume under surface conditions, the logging porosity data, and the gas-oil volume ratio data includes: When the saturation state of the oil and gas reservoir is the single-phase state of the liquid hydrocarbon, the oil saturation is determined according to the crude oil volume factor, the volume of natural gas under surface conditions, the gas-oil ratio, and the logging porosity data.

7. The method for determining the hydrocarbon saturation of a reservoir according to claim 1, wherein, the obtaining of the hydrocarbon saturation of the reservoir based on the saturation state of the oil and gas reservoir, the volume of natural gas under surface conditions, the logging porosity data, and the gas-oil volume ratio data includes: when the saturation state of the oil and gas reservoir is the oil-gas miscible state, the gas saturation is determined according to the gas-oil ratio when the formation pressure is the bubble point pressure, the oil-gas ratio, the gas volume factor, the crude oil volume factor, the volume of natural gas under surface conditions, and the logging porosity data; the oil saturation is determined according to the crude oil volume factor, the volume of natural gas under surface conditions, the gas-oil ratio, and the porosity data; the total hydrocarbon saturation is determined according to the gas-oil ratio when the formation pressure is the bubble point pressure, the oil-gas ratio, the gas volume factor, the crude oil volume factor, the volume of natural gas under surface conditions, and the porosity data.

8. A device for determining the hydrocarbon saturation of a reservoir, wherein, it includes: a first obtaining unit for obtaining gas logging data and porosity data; a second obtaining unit for obtaining the volume of natural gas under surface conditions and the gas-oil ratio data based on the gas logging data, wherein the gas-oil volume ratio data includes the gas volume factor, the crude oil volume factor, the gas-oil ratio, and the gas-oil ratio when the formation pressure is the bubble point pressure, and the hydrocarbon saturation of the reservoir includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation; a third obtaining unit for judging the saturation state of the oil and gas reservoir according to the formation pressure and the bubble point pressure of the oil reservoir, wherein the saturation state of the oil and gas reservoir includes the single-phase state of the liquid hydrocarbon, the single-phase state of the gaseous hydrocarbon, and the oil-gas miscible state; a fourth obtaining unit for obtaining the hydrocarbon saturation of the reservoir based on the saturation state of the oil and gas reservoir, the volume of natural gas under surface conditions, the logging porosity data, and the gas-oil volume ratio data.

9. An electronic device, including: a memory and a processor, wherein the processor is used to implement the steps of the method for determining the hydrocarbon saturation of a reservoir according to any one of claims 1-7 when executing the computer program stored in the memory.

10. A computer-readable storage medium, on which a computer program is stored, wherein: the computer program, when executed by the processor, implements the method for determining the hydrocarbon saturation of a reservoir according to any one of claims 1-7.

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