A method of determining reservoir hydrocarbon saturation and related apparatus

Abstract

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

Description

Technical Field

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

[0002] The calculation of hydrocarbon saturation in oil and gas reservoirs has long been based on geophysical logging data. Archie's formula is commonly used to calculate reservoir fluid saturation in related technologies. However, in oil and gas exploration and development practice, the reservoir fluid saturation calculated using Archie's formula has noticeable errors, especially in low-resistivity oil and gas reservoirs and high-resistivity water layers, where the errors are significant.

[0003] From the perspective of resistivity measurement mechanisms and the establishment mechanism of Archie's formula, calculation deviations stem from the appropriateness of the understanding of Archie parameters a, b, m, and n. Therefore, the difficulty in accurately calculating using Archie's formula lies in obtaining accurate Archie parameters for the target layer. This requires a large amount of costly rock electrical experimental data, which is almost impossible for oil and gas exploration companies operating across vast areas. This has been a challenge encountered by well logging data interpretation technology for nearly a century. Summary of the Invention

[0004] The summary section introduces a series of simplified concepts, which will be further explained in detail in the detailed description section. This summary section is not intended to limit the key and essential technical features of the claimed technical solution, nor is it intended to determine the scope of protection of the claimed technical solution.

[0005] Firstly, this application proposes a method for determining the hydrocarbon saturation of a reservoir, the method comprising:

[0006] Acquire gas logging data and well logging porosity data;

[0007] Based on the above gas logging data, natural gas volume and gas-oil ratio data under surface conditions are obtained. 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. The reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation.

[0008] The saturation state of an oil and gas reservoir is determined based on formation pressure and reservoir bubble point pressure. The saturation state of the oil and gas reservoir includes liquid hydrocarbon single-phase state, gaseous hydrocarbon single-phase state, and oil and gas mixed-phase state.

[0009] Based on the above-mentioned oil and gas reservoir saturation state, natural gas volume under the above-mentioned surface conditions, well logging porosity data, and gas-oil volume ratio data, the hydrocarbon saturation of the reservoir is obtained.

[0010] In one embodiment, the aforementioned gas logging data includes a degassing efficiency correction factor, chromatograph sample gas flow rate, net increase in gas in the outlet drilling fluid, sample gas pipeline pressure, drilling fluid outlet temperature, drilling fluid outlet flow rate, surface temperature, surface pressure, and the flow rate of drilling fluid drawn by the degasser.

[0011] The above-mentioned data on natural gas volume and gas-oil ratio under surface conditions, obtained based on the aforementioned gas logging data, include:

[0012] The volume of natural gas under the above surface conditions is obtained based on the above degassing efficiency correction coefficient, the above chromatograph sample gas flow rate, the above net increase in gas in the above outlet drilling fluid, the above sample gas pipeline pressure, the above drilling fluid outlet temperature, the above drilling fluid outlet flow rate, the above surface temperature, the above surface pressure, and the flow rate of drilling fluid drawn by the above degasser.

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

[0014] The natural gas volume (GSS) under the above surface conditions is determined 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 increase in gas in the outlet drilling fluid, and P tube The above sample gas pipeline pressure, T out The above refers to the drilling fluid outlet temperature, Flrate is the above refers to the drilling fluid outlet flow rate, and T is the drilling fluid outlet temperature. S For the above-mentioned surface temperature, P S For the above surface pressure, Q d The flow rate at which drilling fluid is drawn from the aforementioned degasser.

[0017] In one embodiment, obtaining the reservoir saturation state based on formation pressure and reservoir bubble point pressure includes:

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

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

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

[0021] When the saturation state of the above-mentioned oil and gas reservoir is the above-mentioned single-phase state of gaseous hydrocarbons, the above-mentioned gas saturation is determined based on the above-mentioned gas volume coefficient, the above-mentioned natural gas volume under the above-mentioned surface conditions, and the above-mentioned well logging porosity data.

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

[0023] When the saturation state of the oil and gas reservoir is the single-phase state of liquid hydrocarbons, the oil saturation is determined based on the crude oil volume factor, the natural gas volume under the surface conditions, the gas-oil ratio, and the well logging porosity data.

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

[0025] When the above-mentioned oil and gas reservoir saturation state is the above-mentioned oil and gas miscible state, the above-mentioned gas saturation is determined based on the above-mentioned gas-oil ratio when the formation pressure is the bubble point pressure, the above-mentioned oil-gas ratio, the above-mentioned gas volume coefficient, the above-mentioned crude oil volume coefficient, the above-mentioned natural gas volume under the above-mentioned surface conditions, and the above-mentioned well logging porosity data.

[0026] The oil saturation was determined based on the crude oil volume factor, the natural gas volume under the surface conditions, the gas-oil ratio, and the porosity data.

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

[0028] Secondly, this application also proposes a reservoir hydrocarbon saturation determination device, comprising:

[0029] The first acquisition unit is used to acquire gas logging data and porosity data;

[0030] The second acquisition unit is used to acquire natural gas volume and gas-oil ratio data under surface conditions based on the gas logging data mentioned above. 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. The reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation.

[0031] The third acquisition unit is used to determine the saturation state of the oil and gas reservoir based on the formation pressure and the reservoir bubble point pressure. The saturation state of the oil and gas reservoir includes the liquid hydrocarbon single-phase state, the gaseous hydrocarbon single-phase state, and the oil and gas mixed-phase state.

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

[0033] Thirdly, an electronic device includes: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program stored in the memory to implement the steps of the method for determining reservoir hydrocarbon saturation as described in any of the first aspects above.

[0034] Fourthly, this application also proposes a computer-readable storage medium having a computer program stored thereon, wherein when the computer program is executed by a processor, it implements the method for determining the hydrocarbon saturation of a reservoir according to any one of the preceding claims of the first aspect.

[0035] In summary, the method for determining reservoir hydrocarbon saturation according to this application includes: acquiring gas logging data and well logging porosity data; acquiring 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 reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation; determining the saturation state of the oil and gas reservoir based on the formation pressure and the reservoir bubble point pressure, wherein the saturation state of the oil and gas reservoir includes liquid hydrocarbon single-phase state, gaseous hydrocarbon single-phase state, and oil-gas mixed-phase state; and obtaining the reservoir hydrocarbon saturation based on the oil and gas reservoir saturation state, the natural gas volume under the surface conditions, the well logging porosity data, and the gas-oil volume ratio data. The method for determining reservoir hydrocarbon saturation proposed in this application creatively utilizes calculated data of reservoir physical characteristics parameters obtained from gas logging data, combined with reservoir porosity calculated using geophysical logging methods, to calculate reservoir hydrocarbon saturation data. The hydrocarbon indication data detected by gas logging originates from the actual amount of hydrocarbons in the reservoir and has a good correlation with the reservoir's hydrocarbon saturation. The calculation of hydrocarbon saturation data based on reservoir physical characteristics parameters allows for the calculation of both liquid and gaseous hydrocarbon saturation, enabling accurate determination of natural gas type and oil quality while simultaneously calculating hydrocarbon saturation. Using the method employed in this application, formation factors affecting resistivity do not have a decisive impact on gas indications. The hydrocarbon saturation calculated based on gas logging data is closer to the actual hydrocarbon content of the formation. Comparing the hydrocarbon saturation calculated from gas logging data with the hydrocarbon saturation from well logging allows for the identification of low-resistivity oil layers and high-resistivity water layers, thus improving the overall accuracy of oil and gas layer identification. This application is based on reservoir physics principles, comprehensively utilizes well logging and well logging data, and uses reservoir physics and rock physics calculation methods to realize the data calculation of liquid hydrocarbon saturation and gas hydrocarbon saturation under formation conditions, thereby meeting the technical requirements for reservoir interpretation in the process of oil and gas exploration and development.

[0036] The method for determining reservoir hydrocarbon saturation proposed in this application, along with other advantages, objectives, and features of this application, will be partly apparent from the following description and partly understood by those skilled in the art through study and practice of this application. Attached Figure Description

[0037] Various other advantages and benefits will become apparent to those skilled in the art upon reading the following detailed description of preferred embodiments. The accompanying drawings are for illustrative purposes only and are not intended to limit this specification. Furthermore, the same reference numerals denote the same parts throughout the drawings. In the drawings:

[0038] Figure 1A schematic flowchart of a method for determining the hydrocarbon saturation of a reservoir is provided in this application embodiment;

[0039] Figure 2 A phase diagram showing the distribution of liquid and gaseous hydrocarbons in an oil and gas reservoir is provided in this application embodiment;

[0040] Figure 3 A schematic diagram illustrating the combined calculation of reservoir fluid saturation using gas logging and well logging porosity, provided as an embodiment of this application;

[0041] Figure 4 Another schematic diagram of joint calculation of reservoir fluid saturation by gas logging and well logging porosity provided in this application embodiment;

[0042] Figure 5 A structural schematic diagram of a reservoir hydrocarbon saturation determination device provided in this application embodiment;

[0043] Figure 6 This is a schematic diagram of an electronic device for determining the hydrocarbon saturation of a reservoir, provided as an embodiment of this application. Detailed Implementation

[0044] The terms "first," "second," "third," "fourth," etc. (if present) in the specification, claims, and accompanying drawings of this 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 data can be interchanged where appropriate so that the embodiments described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus. The technical solutions of the embodiments of this application will now be clearly and completely described in conjunction with the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of them.

[0045] The calculation of hydrocarbon saturation in oil and gas reservoirs has long been based on geophysical logging data. Geophysical logging, during oil exploration and extraction, utilizes various instruments to measure the physical parameters of downhole formations and the technical condition of the well, analyzes the recorded data, and conducts geological and engineering studies. Based on the physical foundation of logging methods, the main types include electrical logging, radiometric logging, sonic logging, and formation dip logging. In oil and gas field logging, logging data is primarily used for formation correlation, classifying oil, gas, and water layers; determining important parameters such as reservoir porosity, oil saturation, and permeability; studying the dynamics of oil, gas, and water and the condition of the well during oil and gas field development to provide a basis for development planning; and using logging data along with geological, geophysical, and development data to conduct comprehensive regional geological studies and reservoir description.

[0046] Well logging data interpretation and processing first involves using lithological logging data to calculate a lithological profile, obtaining the reservoir's clay content or the volumetric content of other minerals, and establishing a well logging interpretation lithological profile. Secondly, based on porosity logging data, combined with data such as clay content, the reservoir porosity is calculated. Finally, based on resistivity logging data, the Archie formula is used to calculate the reservoir's oil saturation.

[0047] Archie's formulas are laws concerning the resistivity of sandstone published in 1942 by G.E. Archie, an oil logging engineer at Shell Oilfield Services. Their practical expression is:

[0048]

[0049] Where: a—lithology coefficient related to lithology; b—lithology constant; m—cementation index; n—saturation index; Rw—formation water resistivity, Ω.m; Rt—formation resistivity, Ω.m; Φ—porosity, v / v; S w —Reservoir water saturation, v / v; based on well logging parameters.

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

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

[0052] Archie's formula has a solid physical basis, and 80 years of practical application have verified its usefulness in calculating reservoir fluid saturation. However, it is undeniable that in oil and gas exploration and development, the reservoir fluid saturation calculated using Archie's formula contains perceptible errors, especially in low-resistivity oil and gas reservoirs and high-resistivity water layers, where the errors are significant.

[0053] From the perspective of resistivity measurement mechanisms and the establishment mechanism of Archie's formula, calculation deviations stem from the appropriateness of the understanding of Archie parameters a, b, m, and n. Therefore, the difficulty in accurately calculating using Archie's formula lies in obtaining accurate Archie parameters for the target layer. This requires a large amount of costly rock electrical experimental data, which is almost impossible for oil and gas exploration companies operating across vast areas. This has been a challenge encountered by well logging data interpretation technology for nearly a century.

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

[0055] Oil and gas detection methods in well logging technology are an extension of reservoir geochemical analysis technology applied to drilling operations. They are the most timely and direct means of discovering and evaluating oil and gas reservoirs in oil and gas exploration and development.

[0056] Gas logging is a logging technique that obtains the gas carried by the drilling fluid returning from the bottom of the well. It uses chromatographic analysis to detect and record the composition and total hydrocarbon content of the gas, thereby identifying oil and gas reservoirs. It provides basic data for the discovery and evaluation of oil and gas reservoirs and is one of the main means of discovering oil and gas reservoirs.

[0057] Gas logging parameters mainly include: continuously recorded and automatically detected total hydrocarbons (TG), 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)) and other logging data.

[0058] The most direct parameter reflecting associated gas content is the total hydrocarbon value in gas logging data. The net gas increment can reflect the true gas content of the reservoir and can be used for further calculations.

[0059] In order to quantify the oil and gas content of the formation, technicians used gas standardization calculations to try to obtain quantitative parameters that reflect the oil and gas content of the formation, namely the surface gas content, through correction methods.

[0060] Surface gas content refers to the volume of gas released per unit volume of rock drilled under surface conditions. Changes in the gas volume per unit volume of broken rock reflect changes in the relative porosity and gas saturation of the rock.

[0061] The theoretical basis of surface gas content interpretation methods is the assumption that the natural gas value of a known display section is directly related to the volume of rock fragmentation in that section. When drilling through two identical reservoirs, the hydrocarbon displays will differ significantly due to variations in drilling rate, drilling fluid discharge rate, and drill bit diameter (ignoring uncontrollable factors). The key to formation gas content chart interpretation is standardizing the hydrocarbon displays to eliminate the influence of factors such as drilling time, drill bit, and drilling fluid discharge rate, thereby determining the formation gas content. Therefore, through continuous calculations, the changes in gas content at different depths within the same well can be compared, allowing for the identification of oil, gas, and water layers.

[0062] Through theoretical calculations, the gas content in drilling fluid detected by surface instruments is converted into surface gas content in the rock, providing a quantitative parameter for determining reservoir properties. The NTC calculation derivation comes from the "Technical Specifications for Field Supervision of Exploration and Production Engineering of China National Petroleum Corporation - Geological Supervision Volume," compiled by China National Petroleum Corporation. After considering unit conversions:

[0063]

[0064] Where: TC - the sum of the concentrations of each component, % or 10 -6 Q - Drilling fluid outlet discharge, m 3 / min; ROP - Drilling time, min / m; d - Drill bit outer diameter, mm; k - Degassing efficiency correction value of degasser, currently the degassing efficiency can reach 0.75; NTC - Gas volume content per unit volume of rock under ground conditions, consistent with TC unit.

[0065] NTC is the theoretical surface gas content calculated from gas detection values ​​after eliminating common influencing factors; it is also known as the Gas Normalization value. When TG is used instead of TC in the calculation, the result is called NTG. Because the calculation formulas for NTC and NTG include ROP (Reactive Oxidant Optimum), higher ROP values ​​in tight formations can lead to higher NTC (NTG) values, which are not necessarily due to formation hydrocarbon content. Therefore, the use of NTC (NTG) needs to be constrained. Practice has shown that NTC (NTG) can solve the problem of quantitative calculation to some extent, but there are still many unsatisfactory aspects in its application.

[0066] In 2017, Zhang Guodong published a paper titled "A Full-Scale Forward Modeling Calculation Method for Gas Logging in Determining the Gas-Bearing Nature of Low-Porosity and Low-Permeability Reservoirs," based on the working mechanism of a quantitative degasser. This paper reached a new level of achievement, and the gas standardization calculation formula given in the paper is as follows:

[0067]

[0068] Where: r - wellbore radius, m; v0 - drilling rate, m / min; t - drilling time, min; Φ - rock porosity, %; Sg - gas saturation of fractured rock, %; P_underground - pore pressure of the drilled formation, Pa; T_underground - formation temperature at the drilled site, K, which can be obtained from the geothermal gradient; P_surface - surface atmospheric pressure, Pa; T_surface drilling fluid - temperature of the drilling fluid in the degassing tank, 343.15 K; F_flow rate - drilling fluid flow rate, m³ / min; 300 - volume of drilling fluid obtained per degassing cycle, 300 cm³; 500 - flow rate of the degassing pipeline, 500 cm³ / min; Tg calculation - hydrocarbon concentration in the sample gas pipeline, %; By converting the Tg calculation to the total hydrocarbon value from the gas logging, the reservoir gas saturation value can be obtained.

[0069]

[0070] The logical derivation of this calculation formula is not wrong. The problem lies in the fact that the drilling rate v0 used in it is an engineering construction parameter and t is the drilling time. Although these are quantitatively expressed parameters, they are still qualitative parameters affected by construction factors, not true rock physical parameters. When mixed with gas physical parameters and rock physical parameters such as temperature, pressure, and porosity that are not affected by engineering factors, the final calculation result is distorted.

[0071] Gas component ratios reflect the characteristics of oil and gas reservoirs, and many effective methods have emerged in production practice. Oil and gas reservoirs with different crude oil properties exhibit different characteristics in their associated gas component ratios, such as the Pixler ratio, triangular plot index, and comprehensive gas index. Conversely, the characteristics of underground oil and gas reservoirs can be inferred through these gas component ratio characteristics, identifying whether the gas is dry, wet, light, medium, or heavy. The characteristics of oil and gas reservoirs can be quantitatively expressed through gas component ratios. Oil and gas reservoirs with different crude oil properties have significant differences in their gas-oil ratios, and these ratios can reflect the characteristics of the reservoirs. The gas-oil ratio (GOR) is one of the important characteristic parameters of oil and gas reservoirs, and its value can be calculated using empirical equations based on gas logging data and regional oil and gas well test production data. Other oil and gas reservoir parameters, such as the relative density of natural gas, crude oil density, and viscosity, can all be quantitatively calculated through a series of logical reasoning and data regression processing. During the exploration and evaluation of oil and gas reservoirs, the characteristic parameters of associated gas can be calculated based on gas logging data and corrected by oil and gas well testing and production data. This has practical application value and lays the foundation for the quantitative calculation and evaluation of reservoir hydrocarbon content.

[0072] This invention relates to the field of oil and gas exploration and development data processing technology, and in particular to using gas logging data and porosity logging data, based on oil and gas reservoir characteristic parameters and oil and gas display distribution well sections, and employing computer processing technology to determine the oil and gas saturation of oil and gas reservoirs.

[0073] To address some of the problems existing in the prior art, please refer to Figure 1 This is a schematic flowchart of a method for determining the hydrocarbon saturation of a reservoir, provided in an embodiment of this application. Specifically, it may include:

[0074] S110. Acquire gas logging data and well porosity data;

[0075] For example, the oil and gas indication data detected by gas logging originates from the actual amount of oil and gas in the reservoir and has a good correlation with the reservoir's oil and gas saturation. Based on the calculation of hydrocarbon saturation data using the physical reservoir characteristics parameters, both liquid and gaseous hydrocarbon saturation can be calculated. Simultaneously, accurate determinations of natural gas type and oil quality can be made.

[0076] Well logging porosity is an important concept in geology and petroleum engineering, describing the proportion of voids or pores in a rock or reservoir. Porosity is usually expressed as a percentage, representing the percentage of voids in the total volume of a rock or reservoir.

[0077] S120. Based on the above gas logging data, obtain natural gas volume and gas-oil ratio data under surface conditions, wherein 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] For example, based on the fundamental principles of gas temperature and pressure calculation, natural gas originating from the reservoir, returning to the surface with drilling fluid, experiences three temperature and pressure environments before entering the chromatographic column: the formation environment, the wellhead degasser environment, and the sample gas pipeline environment. The temperature, pressure, and volume of these environments satisfy specific gas equations. Based on gas detection and analysis data, the temperature and pressure conditions of the sample gas, the surface, and the outlet drilling fluid can be used to deduce the natural gas volume under surface conditions. The aforementioned gas-oil volume ratio data includes the gas volume factor, crude oil volume factor, gas-oil ratio, and gas-oil ratio when the formation pressure is the bubble point pressure. The aforementioned reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation.

[0079] S130. Obtain the saturation state of the oil and gas reservoir based on the formation pressure and the reservoir bubble point pressure, wherein the above-mentioned saturation state of the oil and gas reservoir includes the liquid hydrocarbon single-phase state, the gaseous hydrocarbon single-phase state, and the oil and gas mixed-phase state.

[0080] For example, the saturated state of an oil and gas reservoir includes a single-phase liquid hydrocarbon state, a single-phase gaseous hydrocarbon state, and a mixed-phase oil and gas state. The single-phase liquid hydrocarbon state is characterized by the complete dissolution of the gas phase within the liquid phase; the single-phase gaseous hydrocarbon state is characterized by the complete dissolution of the liquid phase within the gas phase; and the mixed-phase oil and gas state is a mixture of the gas and liquid phases. When the formation pressure is greater than the aforementioned reservoir bubble point pressure, the saturated state of the oil and gas reservoir is either the single-phase liquid hydrocarbon state or the single-phase gaseous hydrocarbon state; when the formation pressure is less than the aforementioned reservoir bubble point pressure, the saturated state of the oil and gas reservoir is the mixed-phase oil and gas state.

[0081] S140. Based on the above-mentioned oil and gas reservoir saturation state, the above-mentioned natural gas volume under the above-mentioned surface conditions, the above-mentioned well logging porosity data and gas-oil volume ratio data, the hydrocarbon saturation of the reservoir is obtained.

[0082] For example, after calculating the natural gas volume under surface conditions, the hydrocarbon saturation of the reservoir is calculated using a corresponding formula based on different reservoir saturation states. This formula is related to the natural gas volume, porosity data, and gasoline volume ratio data. The gas-oil volume ratio data includes the gas volume coefficient, crude oil volume coefficient, gas-oil ratio, and the gas-oil ratio at the bubble point pressure. The aforementioned reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation.

[0083] In summary, the method for determining reservoir hydrocarbon saturation proposed in this application creatively utilizes calculated data of reservoir physical oil and gas reservoir characteristic parameters obtained from gas logging data, combined with reservoir porosity calculated using geophysical logging methods, to calculate reservoir hydrocarbon saturation data. The oil and gas indication data detected by gas logging originates from the actual oil and gas content of the reservoir and has a good correlation with the reservoir's hydrocarbon saturation. The calculation of hydrocarbon saturation data based on reservoir physical oil and gas reservoir characteristic parameters can realize the calculation of both liquid and gaseous hydrocarbon saturation, and can accurately determine the type of natural gas and oil quality while calculating hydrocarbon saturation. Using the method adopted in this application, formation factors affecting resistivity do not have a decisive impact on gas indications. The hydrocarbon saturation calculated based on gas logging data is closer to the actual hydrocarbon content of the formation. Comparing the hydrocarbon saturation calculated from gas logging data with the hydrocarbon saturation from well logging can identify low-resistivity oil layers and high-resistivity water layers, thus improving the overall accuracy of oil and gas layer identification. This application is based on reservoir physics principles, comprehensively utilizes well logging and well logging data, and uses reservoir physics and rock physics calculation methods to realize the data calculation of liquid hydrocarbon saturation and gas hydrocarbon saturation under formation conditions, thereby meeting the technical requirements for reservoir interpretation in the process of oil and gas exploration and development.

[0084] In one embodiment, the aforementioned gas logging data includes a degassing efficiency correction factor, chromatograph sample gas flow rate, net increase in gas in the outlet drilling fluid, sample gas pipeline pressure, drilling fluid outlet temperature, drilling fluid outlet flow rate, surface temperature, surface pressure, and the flow rate of drilling fluid drawn by the degasser.

[0085] The above-mentioned data on natural gas volume and gas-oil ratio under surface conditions, obtained based on the aforementioned gas logging data, include:

[0086] The volume of natural gas under the above surface conditions is obtained based on the above degassing efficiency correction coefficient, the above chromatograph sample gas flow rate, the above net increase in gas in the above outlet drilling fluid, the above sample gas pipeline pressure, the above drilling fluid outlet temperature, the above drilling fluid outlet flow rate, the above surface temperature, the above surface pressure, and the flow rate of drilling fluid drawn by the above degasser.

[0087] For example, based on the basic principles of gas temperature and pressure calculation, natural gas originating from the reservoir returns to the surface with the drilling fluid. Before entering the chromatographic column, it exists in three temperature and pressure environments: the formation environment, the wellhead degasser environment, and the sample gas pipeline environment. The gas equations for its temperature, pressure, and volume are as follows:

[0088]

[0089] Based on gas detection and analysis data, the temperature and pressure conditions of sample gas, surface, and outlet drilling fluid can be used to deduce the volume of natural gas under surface conditions. Specifically, the volume of natural gas under surface conditions can be calculated using the degassing efficiency correction coefficient, chromatograph sample gas flow rate, net increase in gas in outlet drilling fluid, sample gas pipeline pressure, drilling fluid outlet temperature, drilling fluid outlet flow rate, surface temperature, surface pressure, and the flow rate of drilling fluid drawn by the degasser.

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

[0091] The natural gas volume (GSS) under the above surface conditions is determined 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 increase in gas in the outlet drilling fluid, and P tube The above sample gas pipeline pressure, T out The above refers to the drilling fluid outlet temperature, Flrate is the above refers to the drilling fluid outlet flow rate, and T is the drilling fluid outlet temperature. S For the above-mentioned surface temperature, P S For the above surface pressure, Q d The flow rate at which drilling fluid is drawn from the aforementioned degasser.

[0094] In one embodiment, obtaining the reservoir saturation state based on formation pressure and reservoir bubble point pressure includes:

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

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

[0097] For example, the reservoir bubble point pressure can be calculated using the empirical formula proposed by Glaso:

[0098]

[0099] in,

[0100]

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

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

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

[0104] For example, when the saturation state of the aforementioned oil and gas reservoir is the aforementioned single-phase state of gaseous hydrocarbons, the gas saturation Sg is:

[0105]

[0106] Among them, B g Here, GSS represents the gas volume factor, GSS represents the natural gas volume under surface conditions, and POR represents the well logging porosity data.

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

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

[0109]

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

[0111] The third type of oil and gas reservoir saturation state: When the above-mentioned oil and gas reservoir saturation state is the above-mentioned oil and gas miscible state, the above-mentioned gas saturation is determined based on the above-mentioned gas-oil ratio when the formation pressure is the bubble point pressure, the above-mentioned oil-gas ratio, the above-mentioned gas volume coefficient, the above-mentioned crude oil volume coefficient, the above-mentioned natural gas volume under the above-mentioned surface conditions, and the above-mentioned well logging porosity data.

[0112] The oil saturation was determined based on the crude oil volume factor, the natural gas volume under the surface conditions, the gas-oil ratio, and the well logging porosity data.

[0113] The total hydrocarbon saturation is determined based on the gas-oil ratio when the formation pressure is the bubble point pressure, the oil-gas ratio, the gas volume coefficient, the crude oil volume coefficient, the natural gas volume under the surface conditions, and the well logging porosity data.

[0114] For example, when the above-mentioned oil and gas reservoir saturation state is the above-mentioned oil and gas miscible state, the gas saturation Sg is:

[0115]

[0116] Oil saturation S O :

[0117]

[0118] Total hydrocarbon saturation S go :

[0119]

[0120] Water saturation is

[0121] S w =1―S go

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

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

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

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

[0126] Bound water volume: POR Swi =POR×S wi

[0127] movable water volume: PORS mw =POR―PORS wi —POR gas —POR o

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

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

[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 in the following way.

[0136] The formation pressure is:

[0137] Pf = 9.8 × 10 -3 ·FP·TVD

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

[0139] The formation temperature is:

[0140] T f=G•TVD+α

[0141] In the formula: T f —Ground temperature, °C; TVD—Vertical well depth, m; G—Ground temperature gradient, °C / 100m; α—Average temperature of the constant temperature zone in the work area, 23 °C can be used as a reference for new exploration areas.

[0142] Natural gas is a mixture and does not have a constant molecular weight. Its molecular weight can be calculated based on gas logging data, using the key rule to determine 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 —The mole fraction of component i in natural gas; M i —Molecular weight of component i in natural gas

[0145] If natural gas and air are both taken under the same standard conditions, the relative density γ of natural gas is... g It can be expressed as follows:

[0146]

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

[0148] The critical pressure P at the natural gas boundary was calculated using the Winn-Sim-Daubert (1980) formula. c and critical temperature Tc

[0149]

[0150]

[0151] In the formula: T c —Critical temperature of the true boiling point fraction, K; p c —Critical pressure of 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 quasi-critical pressure:

[0155] p pc =∑y i p ci

[0156] Calculation of pseudocritical temperature:

[0157] T pc =∑y i T ci

[0158] In the formula: y i —The molar or volume fraction of component i in the natural gas composition; P ci —Critical pressure of component i, MPa; T ci —Critical temperature of component i, K; P pc —Pseudocritical pressure of component i, MPa; T pc —The pseudocritical temperature of component i, in K;

[0159] Calculation of pseudo-comparison parameters for natural gas:

[0160]

[0161]

[0162] In the formula: p pr —Simulated pressure (also denoted as P) r );T pr —Comparison temperature (also denoted as T) r ).

[0163] Standing and Katz published a chart of natural gas deviation coefficients in 1941, showing the relationship between the natural gas deviation coefficient and pressure and temperature. The condition for its use was 0.2 ≤ P. pr ≤15 and 1.05≤T pr The range is ≤3.0. Currently, commonly used natural gas deviation coefficient calculation models are all derived by fitting the above curves, but the different methods used result in different applicable conditions and calculation accuracy.

[0164] Professor Li Xiangfang optimized the curve fitting method and fitted the natural gas deviation coefficient across the entire temperature and pressure range, establishing a high-precision analytical calculation model for the natural gas deviation coefficient. The natural gas deviation coefficient can be calculated using the analytical calculation model for the natural gas deviation coefficient fitted by Professor Li Xiangfang's optimized curve fitting method.

[0165] Gas volume coefficient B gCalculated using the following formula:

[0166]

[0167] In the formula: P sc —Pressure of natural gas under standard conditions, MPa; Tsc—Temperature of natural gas under standard conditions, K; Z—Natural gas deviation coefficient. my country's "Standard Orifice Plate Calculation Method for Natural Gas Flow Rate" stipulates that a temperature of 293.15 K (20℃) and a pressure of 101.325 kPa are used as the standard conditions for measuring gas volumetric flow rate.

[0168] The gas-oil ratio can be calculated using empirical equations for gas parameters, employing the empirical relationship proposed by Glaso based on statistical analysis of oil and gas reservoir samples from the North Sea region:

[0169]

[0170] in:

[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 —Crude oil density, g / cm3; T—Reservoir temperature, K;

[0173] In recent years, with the advancement of technological research, other empirical formulas for calculating the gas-oil ratio based on empirical equations fitted to gas logging data can also be used.

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

[0175]

[0176] in:

[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 when the formation pressure is equal to the bubble point pressure, in m³ / m³; P b —Oil and gas reservoir bubble point (dew point) pressure, MPa;

[0180] The volume factor B0 adopts the empirical formula proposed by Standing:

[0181] B O =0.972 + 0.01213 × D 1.175

[0182] in,

[0183] In the formula: B O - Based on Lu Shuangfang et al.'s "Prediction Model for Volume Factor and Density of Dissolved Gas Crude Oil," an empirical relationship is proposed, which states that the mass of formation crude oil equals the sum of the mass of surface crude oil and the mass of extracted gas:

[0184]

[0185] In the formula:

[0186] d of - Density of formation crude oil, g / cm³ 3

[0187] Based on the oilfield test data of Zhongyuan Oilfield, a statistical regression between the produced gas-oil ratio and the surface crude oil density data yielded an empirical formula for the relationship between density and gas-oil ratio:

[0188]

[0189] Where: c - regional empirical coefficient, 0.9694 is used for reference; d - regional empirical coefficient, -0.028 is used for reference; Rs - gas-oil ratio produced, m 3 / m 3 ;γ o - Surface crude oil density, g / cm³ 3

[0190] Commonly used formulas for calculating clay content using natural gamma (GR) logging data:

[0191]

[0192] Where: SH – relative natural gamma value; GR – natural gamma logging value of the target layer; GRmin – natural gamma logging value of pure lithological formations; GRmax – natural gamma logging value of pure mudstone formations.

[0193]

[0194] In the formula, Vsh is the clay content, a decimal; GCUR is an empirical coefficient related to the age of the strata, which is 3.7 for new strata and 2 for old strata.

[0195] Methods for calculating porosity from well logging data include sonic transit time, density logging, and compensated neutron logging data.

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

[0197]

[0198] In the formula: Φs – porosity calculated by acoustic wave, decimal; DTma and DTf – acoustic transit time of rock skeleton and formation fluid, respectively, μs / m; Vsh – formation clay content, decimal; CP – acoustic compaction correction coefficient, which can be obtained statistically from core analysis porosity and acoustic wave calculated porosity, or statistically from density porosity and acoustic wave porosity; DT – acoustic transit time logging value of the target layer, μs / m.

[0199] Porosity calculated based on density logging data

[0200]

[0201] In the formula: Φ D - Density porosity, decimal; D ma D f —These represent the density values ​​of the rock skeleton and the formation fluid, respectively, in g / cm³. 3 DEN – Target layer density logging value, g / cm3; D sh - Density of mudstone, g / cm3; V sh - Reservoir clay content, decimal.

[0202] Porosity was calculated using compensated neutron logging data.

[0203] ΦN=(CN-LCOR-0.5×Vsh×Nsh)×0.01

[0204] Where: Φ N - Neutron porosity, decimal; CN - Target layer compensated neutron logging value, %; LCOR - Rock skeleton neutron value, %; Vsh - Target layer clay content, decimal; Nsh - Mudstone neutron value, %.

[0205] An empirical formula for calculating bound water saturation was established based on porosity, clay content, and wettability:

[0206]

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

[0208]

[0209] when At that time, take When the calculated result Swi ≤ 0.15, take Swi = 0.15.

[0210] Once sufficient analytical data is available for the exploration area, an empirical formula for calculating the bound water saturation of the area can be established.

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

[0212] POR swi =POR×S wi

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

[0214] PORA = POR - POR swi

[0215] Where: PORA—volume of effective reservoir space; POR Swi —The volume of rock occupied by bound water in the reservoir; PORA is the volume of the effective storage space in the reservoir.

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

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

[0218] During overbalanced drilling, wellbore fluid enters the formation. At this time, the combined volume of crude oil and natural gas carried to the wellhead will be less than the value of PORA.

[0219] When calculating hydrocarbon saturation using a combination of logging and well logging data, the sum of gas components is TC:

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

[0221] DTC = TC - TCBK

[0222] Where: DTC—component and net asset value data, %; TCBK—component and curve baseline value, %.

[0223] or:

[0224] DTG = TG - TGBK

[0225] Where: DTG -- net total hydrocarbon value, %; TG -- total hydrocarbon detection value, %; TGBK -- baseline value of total hydrocarbon curve, %.

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

[0227]

[0228] Where: Vos—the volume of crude oil returned to the surface with the drilling fluid, in m³ 3 GOR—Gas-to-oil ratio, m 3 / m 3 ;

[0229] The volume of formation gas is:

[0230] G f =B g ×GSS

[0231] In the formula G f —Gas volume under formation temperature and pressure conditions, m 3 ;

[0232] The volume of crude oil in the formation is:

[0233] V of =B o ×V os

[0234] In the formula: V of —Crude oil volume under formation temperature and pressure conditions, m 3 ;

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

[0236] V gof =G f +V os

[0237] In the formula: V gof —The single-phase state of gas and crude oil under formation temperature and pressure conditions.

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

[0239]

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

[0241]

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

[0243] When the formation pressure is less than the reservoir bubble point pressure, the reservoir fluid is a mixed state of liquid and gaseous hydrocarbons. Part of the gaseous hydrocarbons are dissolved in the liquid crude oil, and part of them exist in the reservoir in a gaseous state.

[0244] A schematic diagram showing the ratio of liquid to gas phases in an oil reservoir under the given temperature and pressure conditions is shown below. Figure 2 As shown.

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

[0246] In the two-phase region, the value of the free phase gaseous state 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 specific volume, m 3 ;

[0249] When the formation pressure is greater than the reservoir bubble point pressure, the reservoir fluid is either liquid hydrocarbon or gaseous hydrocarbon.

[0250] (GOR), m3 / m3

[0251] Formation gas phase to liquid hydrocarbon volume ratio

[0252]

[0253] Formation gaseous hydrocarbon volume:

[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 utilizes calculation data of reservoir physical oil and gas characteristic parameters, based on net gas increment data from gas logging data, and combined with reservoir logging porosity data calculated using 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 using numerical tables and graphs, providing a fundamental method for the refined interpretation of reservoir fluid properties.

[0264] In the Chad exploration area of ​​Africa, the hydrocarbon saturation of sandstone reservoirs was calculated using well logging-well logging methods. The results are illustrated in the diagram below. Figure 3 As shown, calculations yielded the reservoir's oil and gas saturation, as well as the volumetric values ​​of liquid oil, gaseous hydrocarbons, and water in the reservoir pores, POR. o POR g and POR w The cross-sectional view visually demonstrates the occurrence of oil, gas, and water in the reservoir. Figure 3 The gas logging data includes: C1-methane, 10 -6 C2-Ethane, 10 -6 C3-propane, 10 -6 iC4—isobutane, 10 -6 nC4—n-Butane, 10 -6 iC5—isopentane, 10 -6 nC5—n-pentane, 10 -6 TG—All hydrocarbons, 10 -6 Logging parameters include: BS—drill bit size, mm; CAL—wellbore diameter, mm; GR—natural gamma ray, API; SP—spontaneous potential, mV; RHOB—density logging, g / cm³. 3 NPHI—neutron logging, v / v; DT—sonic transit 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] The technical methods of this invention have been applied in both carbonate and sandstone reservoirs, achieving good verification results. In the K13 oil and gas field of the Chad exploration area in Africa, good oil and gas shows were encountered in the sandstone reservoir. Based on the characteristics of gas logging data, reservoir physical diagnostic parameters were calculated, and combined with geophysical logging porosity data, hydrocarbon saturation data were calculated. The calculation results are as follows: Figure 4As shown. Based on logging data, the section from 2001.30 to 2009.38m in well K13 was interpreted as an oil layer, and based on the gas logging ratio characteristics, it was interpreted as a gas layer. According to the reservoir's physical diagnostic parameters, gas saturation and oil saturation were calculated separately. Based on the calculation results, the section from 2001.30 to 2009.38m was predominantly gas-bearing with relatively low liquid hydrocarbon content. In subsequent oil testing, after perforation at 2001.30 to 2009.38m, a 32 / 64in nozzle was used, resulting in a natural gas production of 253,070 m³. 3 / d, liquid oil was not measured. The oil test results are consistent with the conclusions obtained using the calculation method of this invention.

[0266] Please see Figure 5 One embodiment of the reservoir hydrocarbon saturation determination device in this application may include:

[0267] The first acquisition unit 21 is used to acquire gas logging data and logging porosity data;

[0268] The second acquisition unit 22 is used to acquire natural gas volume and gas-oil ratio data under surface conditions based on the gas logging data mentioned above. 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. The reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation.

[0269] The third acquisition unit 23 is used to acquire the saturation state of the oil and gas reservoir based on the formation pressure and the reservoir bubble point pressure, wherein the saturation state of the oil and gas reservoir includes the liquid hydrocarbon single-phase state, the gaseous hydrocarbon single-phase state and the oil and gas mixed-phase state.

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

[0271] like Figure 6 As shown, this application embodiment also 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, it implements the steps of any of the above-described methods for determining the hydrocarbon saturation of the reservoir.

[0272] Since the electronic device described in this embodiment is the device used to implement the reservoir hydrocarbon saturation determination device in the embodiments of this application, those skilled in the art can understand the specific implementation method and various variations of the electronic device in this embodiment based on the method described in the embodiments of this application. Therefore, how the electronic device implements the method in the embodiments of this application will not be described in detail here. Any device used by those skilled in the art to implement the method in the embodiments of this application falls within the scope of protection of this application.

[0273] In practical implementation, when the computer program 311 is executed by the processor, it can achieve the following: Figure 1 Any of the corresponding implementation methods in the embodiments.

[0274] It should be noted that the descriptions of each embodiment in the above embodiments have different focuses. For parts that are not described in detail in a certain embodiment, please refer to the relevant descriptions in other embodiments.

[0275] The above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit it. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this application.

Claims

1. A method for determining the hydrocarbon saturation of a logging reservoir, characterized in that, include: Acquire gas logging data and well logging porosity data; Based on the gas logging data, natural gas volume and gas-oil volume ratio data under surface conditions are obtained. The gas-oil volume ratio data includes gas volume coefficient, crude oil volume coefficient, oil-gas ratio, and gas-oil ratio when the formation pressure is the bubble point pressure. The reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation. The saturation state of an oil and gas reservoir is determined based on formation pressure and reservoir bubble point pressure. The saturation state of the oil and gas reservoir includes liquid hydrocarbon single-phase state, gaseous hydrocarbon single-phase state, and oil and gas mixed-phase state. The hydrocarbon saturation of the reservoir is obtained based on the saturation state of the oil and gas reservoir, the natural gas volume under the surface conditions, the well logging porosity data, and the gas-oil volume ratio data. The gas logging data includes the degassing efficiency correction factor, chromatograph sample gas flow rate, net increase in gas in the outlet drilling fluid, sample gas pipeline pressure, drilling fluid outlet temperature, drilling fluid outlet flow rate, surface temperature, surface pressure, and the flow rate of drilling fluid drawn by the degasser. The acquisition of natural gas volume and gas-oil volume ratio data under surface conditions based on the gas logging data includes: The volume of natural gas under the surface conditions is obtained based on the degassing efficiency correction coefficient, the sample gas flow rate of the chromatograph, the net increase in gas 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 drilling fluid drawn by the degasser. Also includes: The natural gas volume (GSS) under the aforementioned surface conditions is determined based on the following formula: In the formula, k is the degassing efficiency correction coefficient, Q is the sample gas flow rate of the chromatograph, DTC is the net increase in gas in the outlet drilling fluid, and P tube The sample gas pipeline pressure, T out The drilling fluid outlet temperature is T, Flrate is the drilling fluid outlet flow rate, and T is the drilling fluid outlet temperature. S For the surface temperature, P S For the surface pressure, Q d The flow rate at which drilling fluid is drawn from the degasser.

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

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

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

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

6. A reservoir hydrocarbon saturation determination device, used to implement the logging method for determining reservoir hydrocarbon saturation as described in any one of claims 1-5, characterized in that, include: The first acquisition unit is used to acquire gas logging data and well logging porosity data; The second acquisition unit is used to acquire natural gas volume and gas-oil volume ratio data under surface conditions based on the gas logging data. The gas-oil volume ratio data includes gas volume coefficient, crude oil volume coefficient, oil-gas ratio, and gas-oil ratio when the formation pressure is the bubble point pressure. The reservoir hydrocarbon saturation includes at least one of gas saturation, oil saturation, and total hydrocarbon saturation. The third acquisition unit is used to determine the saturation state of the oil and gas reservoir based on the formation pressure and the reservoir bubble point pressure. The saturation state of the oil and gas reservoir includes the liquid hydrocarbon single-phase state, the gaseous hydrocarbon single-phase state, and the oil and gas mixed-phase state. The fourth acquisition unit is used to acquire 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 well logging porosity data, and the gas-oil volume ratio data.

7. An electronic device, comprising: The memory and processor are characterized in that the processor is used to execute a computer program stored in the memory to implement the steps of the method for determining the hydrocarbon saturation of a reservoir as described in any one of claims 1-5.

8. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the computer program is executed by the processor, it implements the method for determining the hydrocarbon saturation of a reservoir as described in any one of claims 1-5.

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