Oil and gas phase type identification method and system

Abstract

The present application belongs to the technical field of oil and gas geological exploration and development, and relates to a method and system for identifying oil and gas phase types. The method comprises the following steps: obtaining well logging data and mud logging data of the target layer in the study area; selecting phase prediction indicators for the target layer in the study area based on the well logging data, and selecting multiple sample points of known phase types in the study area based on the mud logging data; calculating the principal components of the target layer according to the phase prediction indicators, and establishing a ground-logging-integrated phase prediction map based on the multiple sample points and the calculated principal component projection points; determining the classification criteria for oil and gas phase types based on the gas logging response values of the hydrocarbon components of the oil and gas samples, and superimposing the classification criteria on the ground-logging-integrated phase prediction map to form a phase prediction map containing critical phase types; and identifying the oil and gas phase types of the target layer in the study area based on the phase prediction map containing critical phase types. The present application can accurately identify the oil and gas phase types of oil and gas reservoirs and achieve the subdivision of critical phase types.

Description

Technical Field

[0001] The present application belongs to the technical field of oil and gas geological exploration and development, and specifically relates to a method and system for identifying oil and gas phase types. Background Art

[0002] In deep reservoirs within a basin, oil and gas can exist as a single oil phase, a gas phase, or a mixture of oil and gas. Once extracted to the surface, oil and natural gas undergo a series of phase transitions due to decreasing temperature and pressure, presenting phase types different from those found in deeper reservoirs. Based on the specific gravity of hydrocarbons, they can be classified as extra-heavy oil, heavy oil, medium oil, light oil (volatile oil), condensate gas, and natural gas. Based on the gas-oil ratio, they can be classified as black oil, light oil (volatile oil), condensate gas, wet gas, and dry gas. The complexity and uncertainty of oil and gas phase types pose significant challenges to oil and gas exploration and development. Therefore, clarifying phase types and clarifying their spatial distribution characteristics and causes will facilitate oil and gas exploration and development.

[0003] Current research on oil and gas phase behavior uses commonly used experimental sample analysis methods, including crude oil cracking experiments, conventional column chromatography, and high-temperature hot-pressing simulations. Previous research has summarized three main categories of oil and gas phase identification methods: empirical statistical identification, phase diagram identification, and predictive modeling.

[0004] The empirical statistical method is to summarize the regularity of different types of oil and gas reservoirs based on the composition and characteristic parameters of a large number of known oil and gas reservoirs, thereby guiding the identification of oil and gas reservoir phase types. There are 14 known empirical statistical methods, namely, the box diagram method, C 2+ Content method, φ 1 parameter method, formation fluid density and average molecular weight method, reservoir fluid ternary composition triangle diagram method, gas-oil ratio and unit reservoir fluid production tank oil volume relationship method, surface production gas-oil ratio and tank oil density relationship method, reservoir condensate gas C 5+ Value method, reservoir condensate gas C1 / C 5+ Value method, grade classification method, Z factor method, potential function method, iC4 / nC4 and iC5 / nC5 method, C 5+ and N2 relationship method. Among them, the reservoir fluid ternary composition triangle diagram method, φ The four empirical statistical methods, namely the 1-parameter method, the formation fluid density and average molecular weight method, and the relationship between the gas-oil ratio and the unit reservoir fluid production tank oil volume method, are commonly used methods for oil and gas phase state discrimination because they are relatively accurate in discriminating the oil and gas phase state.

[0005] Phase diagram identification methods include the PVT phase diagram method, the liquid volume versus dimensionless pressure curve method, the condensate oil content versus saturation pressure curve method, and the dimensionless shrinkage versus dimensionless pressure curve method. The PVT phase diagram method uses PVTsim software to draw a PVT phase diagram based on the compositional characteristics of hydrocarbon fluids. The different phase types are identified based on the PVT phase diagram characteristics and the location of the reservoir temperature isothermal decompression line for each reservoir. For condensate reservoirs, if the formation pressure is close to or equal to the dew point, the presence of an oil ring can often be predicted. For near-critical condensate reservoirs or volatile oil reservoirs, accurately determining the fluid critical point is crucial. The liquid volume versus dimensionless pressure curve method uses the shape and location of the curve plotting the liquid volume percentage (relative to the saturation pressure point) versus the dimensionless pressure (relative to the saturation pressure) obtained from fluid phase behavior experiments to roughly identify the reservoir type. The condensate content vs. saturation pressure curve method uses well gas and condensate samples prepared in the laboratory at different gas-to-oil ratios. The saturation pressures of each sample are measured and plotted to determine reservoir type. The dimensionless shrinkage rate vs. dimensionless pressure curve method uses PVT data from crude oil samples from specific reservoirs to calculate the dimensionless shrinkage rate and pressure. The plot then identifies the reservoir fluid type within the oil-producing layer.

[0006] Predictive modeling is also a commonly used method for identifying phase types. Existing phase prediction models, both domestically and internationally, are mostly based on mud logging or well data, such as the Pickles chart, hydrocarbon gas component value chart, or hydrocarbon component ratio chart. The Pickles chart classifies oil and gas layers into non-producing, gas, and oil layers based on the numerical ranges of C1 / C2, C1 / C3, C1 / C4, and C1 / C5 within the hydrocarbon components. The hydrocarbon gas component value or hydrocarbon component ratio chart selects a single component from the hydrocarbon gas composition that represents the characteristics of oil, gas, and water. Using two or three components or ratio parameters that clearly delineate the boundaries between oil, gas, and water layers, a coordinate system is constructed. Based on the well test results, the oil, gas, and water intervals are demarcated, creating a chart. The chart is then graphically illustrated to distinguish between oil, gas, and water layers. The gas component value cross plot and the triangular component chart are two of the more commonly used methods.

[0007] Existing methods for identifying oil and gas phase types have the following two main problems: (1) Most methods require the use of hydrocarbon fluid composition data for identification. However, for well locations where hydrocarbon fluid composition data is lacking, the application of these methods will be limited, making it impossible to identify the oil and gas phase type. (2) Existing domestic and foreign phase prediction models are mostly based on well logging or well logging data. The accuracy of identifying phase types varies in different study areas, resulting in low identification accuracy. Summary of the Invention

[0008] In response to the problems existing in the prior art, this application provides a method and system for identifying oil and gas phase types. Taking into account the geological background, a phase prediction model is established based on gas logging and well logging responses. The established model accurately identifies the oil and gas phase types of oil and gas reservoirs, realizes the subdivision of critical state types, and further clarifies the spatial distribution characteristics and causal mechanisms of different oil and gas phase types, and formulates corresponding oil and gas exploration and development strategies.

[0009] In a first aspect, the present application provides a method for identifying oil and gas phase types, the steps of which are as follows:

[0010] Obtain well logging data and mud logging data of the target layer in the study area;

[0011] Select phase prediction indicators of the target layer in the study area based on well logging data, and select multiple sample points of known phase types of the target layer in the study area based on logging data;

[0012] Calculate the principal components of the target stratum according to the phase state prediction index, and establish a phase state prediction chart based on multiple sample points and principal component projection points;

[0013] The classification standard of oil and gas phase types is determined based on the gas test response value of hydrocarbon components in oil and gas samples, and the classification standard is superimposed on the phase prediction plate to form a phase prediction plate containing critical phase types;

[0014] The oil and gas phase types of the target layers in the study area are identified based on the phase prediction chart containing critical phase types.

[0015] In some embodiments, the phase prediction index includes acoustic wave time difference DT, gamma value GR, resistivity value R, gas measurement value Tg, gas measurement value C1, hydrocarbon moisture ratio Wh, and the difference between hydrocarbon moisture ratio Wh and hydrocarbon equilibrium ratio Bh.

[0016] In some embodiments, the acoustic time difference DT, gamma value GR, resistivity value R, gas logging value Tg, and gas logging value C1 are directly read from the well logging curve of the target layer in the study area; the hydrocarbon moisture ratio Wh and hydrocarbon balance ratio Bh are calculated based on the gas logging response values of the hydrocarbon components of the oil and gas samples;

[0017]

[0018]

[0019] Where C1, C2, C3, C4, C5, iC4, nC4, iC5, and nC5 are the gas measurement response values of the corresponding hydrocarbon components.

[0020] In some embodiments, the method for calculating the principal component of the target formation based on the phase prediction index is:

[0021] The phase state prediction index is standardized to obtain a standardized phase state prediction index;

[0022] Calculate principal component I and principal component II respectively;

[0023] Principal component I = 0.27*A1-0.10*A2-0.22*A3+0.56*A4+0.56*A5-0.34*A6-0.34*A7

[0024] Principal component II = -0.61*A1+0.25*A2+0.65*A3+0.18*A4+0.21*A5-0.19*A6-0.13*A7

[0025] Wherein, A1 is the standardized acoustic time difference DT, A2 is the standardized gamma value GR, A3 is the standardized resistivity value R, A4 is the standardized gas measurement value Tg, A5 is the standardized gas measurement value C1, A6 is the standardized hydrocarbon moisture ratio Wh, and A7 is the difference between the standardized hydrocarbon moisture ratio Wh and the hydrocarbon balance ratio Bh.

[0026] In some embodiments, the method for determining the classification standard of oil and gas phase types based on the gas detection response value of the hydrocarbon components of the oil and gas sample is:

[0027] Calculated based on the gas test response value of hydrocarbon components in oil and gas samples φ 1 parameter;

[0028]

[0029] Where, C1, C2, C3, C4, C5 + are the gas measurement response values corresponding to the hydrocarbon components;

[0030] According to the calculated φ 1 parameter to obtain the classification standard of oil and gas phase types.

[0031] In some embodiments, based on the calculated φ 1 parameter to obtain the classification standard of oil and gas phase types: φ When 1≤2.5, the oil and gas phase type is black oil. φ When 1≤1, the oil and gas phase type is high viscosity heavy oil reservoir, when 1< φ When 1≤2.5, the oil and gas phase type is ordinary black oil reservoir; when 2.5< φ When 1≤15, the oil and gas phase type is volatile oil, and when 2.5< φ When 1≤7, the oil and gas phase type is volatile oil reservoir, when 7< φ When 1≤15, the oil and gas phase type is condensate gas cap reservoir; when φ When 1>15, the oil and gas phase type is condensate gas. φWhen 1≤80, the oil and gas phase type is a condensate gas reservoir with oil ring; when φ When 1>80, the oil and gas phase type is a condensate gas reservoir without oil ring.

[0032] In a second aspect of the present application, a system for identifying oil and gas phase types is provided, which is used to implement the oil and gas phase type identification method described in the first aspect of the present application, comprising:

[0033] Acquisition module, used to obtain well logging data and mud logging data of the target layer in the study area;

[0034] Selection module, which selects the phase state prediction index of the target layer in the study area based on the well logging data, and multiple sample points with known phase state types based on the logging data;

[0035] A calculation module calculates the principal components of the target layer based on the phase prediction index;

[0036] A chart construction module is used to build a phase prediction chart based on multiple sample points obtained and the calculated principal component projection points;

[0037] The classification standard discrimination module determines the classification standard of oil and gas phase types based on the gas testing response value of hydrocarbon components in oil and gas samples;

[0038] A superposition module superimposes the classification criteria on the phase state prediction plate to form a phase state prediction plate containing critical phase state types;

[0039] The phase type identification module identifies the oil and gas phase type of the target layer in the study area based on the phase prediction map containing critical phase types.

[0040] Compared with the prior art, the advantages and positive effects of this application are:

[0041] The oil and gas phase type identification method and system provided in this application integrates geological background, gas logging, and well logging responses to establish an oil and gas phase prediction model. The oil and gas phase type classification criteria, determined based on the gas logging response values of hydrocarbon components in oil and gas samples, are superimposed on a phase prediction map to form a phase prediction map containing critical phase types. The oil and gas phase types of the target layer in the study area are identified based on the phase prediction map containing critical phase types. This system can accurately identify the oil and gas phase types in deep reservoirs, achieve a subdivision of critical phase types, and further clarify the spatial distribution characteristics and genetic mechanisms of different phase types, allowing the formulation of corresponding oil and gas exploration and development strategies. This system has important guiding significance for the exploration and development of deep oil and gas reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0042] Figure 1 This is a flow chart of the oil and gas phase type identification method described in an embodiment of the present application;

[0043] Figure 2This is a flow chart of a method for calculating the principal components of a target formation according to a phase prediction index according to an embodiment of the present application;

[0044] Figure 3 This is a flow chart of a method for determining the classification standard of oil and gas phase types based on the gas measurement response values of hydrocarbon components of oil and gas samples according to an embodiment of the present application;

[0045] Figure 4 This is a structural block diagram of the oil and gas phase type identification system described in an embodiment of the present application;

[0046] Figure 5 A schematic diagram of a phase prediction diagram including critical phase types according to an embodiment of the present application;

[0047] Figure 6 This is a schematic diagram of the results of the oil and gas phase type identification in the C layer of Well A using the phase prediction chart containing critical phase types in the embodiment of the present application;

[0048] Figure 7 This is a schematic diagram of the results of the oil and gas phase type identification in the D layer of Well A using the phase prediction chart containing critical phase types in the embodiment of the present application;

[0049] Figure 8 This is a schematic diagram of the results of oil and gas phase type identification in Well B using a phase prediction chart containing critical phase types in an embodiment of the present application.

[0050] In the figure, 1. Acquisition module, 2. Selection module, 3. Calculation module, 4. Plate construction module, 5. Division standard judgment module, 6. Superposition module, 7. Phase type judgment module. DETAILED DESCRIPTION

[0051] The present application will be described in detail below with reference to exemplary embodiments in conjunction with the accompanying drawings. However, it should be understood that elements, structures, and features in one embodiment may also be beneficially combined in other embodiments without further description.

[0052] The present application provides a method and system for identifying oil and gas phase types. By integrating well logging data and mud logging data, and combining principal component analysis and gas logging response values, a phase prediction map is constructed, and the identified oil and gas phase type classification standards are superimposed on the phase prediction map to obtain a phase prediction map containing critical phase types. By using the phase prediction map containing critical phase types, the oil and gas phase types of deep reservoirs can be comprehensively and systematically identified. Compared with the method of a single data source, it has higher accuracy and can provide a more reliable basis for oil and gas exploration and development. The following is a detailed description of the above-mentioned oil and gas phase type identification method and system in conjunction with the accompanying drawings.

[0053] See also Figure 1The first embodiment of the present application provides a method for identifying oil and gas phase types, the steps of which are as follows:

[0054] S1. Obtain the well logging data and mud recording data of the target layer in the study area.

[0055] S2. Select phase prediction indicators of the target layer in the study area based on the well logging data, and select multiple sample points of known phase types of the target layer in the study area based on the logging data.

[0056] Specifically, in some embodiments of the application, the phase prediction indicators include acoustic time difference DT, gamma value GR, resistivity value R, gas measurement value Tg, gas measurement value C1, hydrocarbon moisture ratio Wh, and the difference between the hydrocarbon moisture ratio Wh and the hydrocarbon equilibrium ratio Bh.

[0057] It should be noted that each logging parameter is controlled by different influencing factors, which leads to certain errors in the application of the phase prediction model established based on logging or well data. In the embodiment of the present application, taking into account the geological background, seven phase prediction indicators are selected, including acoustic time difference DT, gamma value GR, resistivity value R, gas measurement value Tg, gas measurement value C1, hydrocarbon moisture ratio Wh, and the difference between hydrocarbon moisture ratio Wh and hydrocarbon equilibrium ratio Bh. These indicators cover rock physical properties (acoustic time difference, gamma value, resistivity) and fluid properties (gas measurement value, hydrocarbon moisture ratio, etc.). The comprehensive application of these indicators can more comprehensively reflect the geological characteristics and fluid properties of oil and gas reservoirs, thereby improving the accuracy of phase identification.

[0058] Specifically, in some embodiments of the present invention, the acoustic time difference (DT), gamma value (GR), resistivity value (R), gas logging value (Tg), and gas logging value (C1) are directly read from the well logging curve of the target layer in the study area. The hydrocarbon moisture ratio (Wh) and hydrocarbon balance ratio (Bh) are calculated based on the gas logging response values of the hydrocarbon components of the oil and gas samples.

[0059]

[0060]

[0061] Where C1, C2, C3, C4, C5, iC4, nC4, iC5, and nC5 are the gas logging response values of the corresponding hydrocarbon components, which can be derived from the logging curve.

[0062] In this application, efficient data acquisition and processing is achieved by directly reading some indicators from well logging curves and calculating the hydrocarbon moisture ratio and hydrocarbon equilibrium ratio based on the gas logging response values. This data processing method not only improves work efficiency but also ensures data accuracy and consistency, providing high-quality data support for subsequent phase state identification.

[0063] S3. Calculate the principal components of the target layer based on the phase prediction index, and establish a phase prediction chart based on multiple sample points and principal component projection points.

[0064] In some embodiments of the application, see Figure 2 , the method for calculating the principal components of the target layer according to the phase prediction index is:

[0065] S31. Standardizing the phase state prediction index to obtain a standardized phase state prediction index. Standardizing the phase state prediction index can reduce errors and eliminate the influence of different logging parameters.

[0066] S32, calculate principal component I and principal component II respectively;

[0067] Principal component I = 0.27*A1-0.10*A2-0.22*A3+0.56*A4+0.56*A5-0.34*A6-0.34*A7

[0068] Principal component II = -0.61*A1+0.25*A2+0.65*A3+0.18*A4+0.21*A5-0.19*A6-0.13*A7

[0069] Wherein, A1 is the standardized acoustic time difference DT, A2 is the standardized gamma value GR, A3 is the standardized resistivity value R, A4 is the standardized gas measurement value Tg, A5 is the standardized gas measurement value C1, A6 is the standardized hydrocarbon moisture ratio Wh, and A7 is the difference between the standardized hydrocarbon moisture ratio Wh and the hydrocarbon balance ratio Bh.

[0070] In the examples of this application, principal component analysis (PCA) is used to calculate principal components I and II using specific weight coefficients. This effectively extracts key information, reduces data dimensionality, and retains the most important geological and fluid characteristics. This helps simplify the constructed phase prediction model and improves its stability and prediction accuracy.

[0071] S4. Determine the classification standard of oil and gas phase types based on the gas test response values of hydrocarbon components of the oil and gas samples, and superimpose the classification standard on the phase prediction chart to form a phase prediction chart containing critical phase types.

[0072] In some embodiments of the application, see Figure 3 The method for distinguishing the classification standard of oil and gas phase types based on the gas testing response value of hydrocarbon components in oil and gas samples is as follows:

[0073] S41. Calculation based on the gas test response value of hydrocarbon components in oil and gas samples φ 1 parameter;

[0074]

[0075] Where, C1, C2, C3, C4, C5 + are the gas measurement response values corresponding to the hydrocarbon components;

[0076] S42, according to the calculation φ 1 parameter to obtain the classification standard of oil and gas phase types.

[0077] In the embodiment of this application, by calculating φ 1 parameter and classify oil and gas phase types accordingly, providing a quantitative and standardized method for phase identification. This method can avoid the subjectivity of human experience, making phase identification more objective and accurate, and facilitating its application in different regions and oil and gas reservoirs.

[0078] In some embodiments of the application, according to the calculated φ 1 parameter to obtain the classification standard of oil and gas phase types: φ When 1≤2.5, the oil and gas phase type is black oil. φ When 1≤1, the oil and gas phase type is high viscosity heavy oil reservoir, when 1< φ When 1≤2.5, the oil and gas phase type is ordinary black oil reservoir; when 2.5< φ When 1≤15, the oil and gas phase type is volatile oil, and when 2.5< φ When 1≤7, the oil and gas phase type is volatile oil reservoir, when 7< φ When 1≤15, the oil and gas phase type is condensate gas cap reservoir; when φ When 1>15, the oil and gas phase type is condensate gas. φ When 1≤80, the oil and gas phase type is a condensate gas reservoir with oil ring; when φ When 1>80, the oil and gas phase type is a condensate gas reservoir without oil ring.

[0079] In the embodiment of this application, different φ The oil and gas phase types corresponding to the parameter value ranges include black oil, volatile oil, and condensate gas, and the specific conditions of each type are further subdivided. This refined classification standard can more accurately reflect the phase characteristics of oil and gas reservoirs and provide a more detailed basis for oil and gas reservoir classification evaluation and development strategy formulation.

[0080] S5. Identify the oil and gas phase types of the target layer in the study area based on the phase prediction map containing critical phase types.

[0081] The above-mentioned oil and gas phase type identification method of this application is described in Figure 4 The second embodiment of the present application provides an oil and gas phase type identification system for implementing the oil and gas phase type identification method described in the first aspect of the present application, including:

[0082] Acquisition module 1 is used to obtain well logging data and mud logging data of the target layer in the study area;

[0083] Selection module 2, selecting phase state prediction indicators of the target layer in the study area based on well logging data, and multiple sample points with known phase state types based on logging data;

[0084] Calculation module 3, calculates the principal component of the target layer according to the phase prediction index;

[0085] A chart construction module 4 is used to build a phase state prediction chart based on the obtained multiple sample points and the calculated principal component projection points;

[0086] The classification standard judgment module 5 is used to judge the classification standard of the oil and gas phase type according to the gas test response value of the hydrocarbon components of the oil and gas sample;

[0087] A superposition module 6 superimposes the classification criteria on the phase state prediction plate to form a phase state prediction plate containing critical phase state types;

[0088] Phase type identification module 7 identifies the oil and gas phase type of the target layer in the study area based on the phase prediction map containing critical phase types. The oil and gas phase type identification system described in this application, through modular design, achieves full automation and systematization of the entire process from data acquisition to phase identification. Each module has a clear division of labor and works collaboratively, which not only improves work efficiency but also reduces errors in human operation. This systematic solution can better meet the needs of large-scale oil and gas exploration and development, and provides strong support for the digital management of oil and gas fields.

[0089] In order to verify the effectiveness of the oil and gas phase type identification method and system described in the above embodiments of this application, the following specific embodiments are used for illustration.

[0090] Example: Take well A and well B in a certain study area as an example.

[0091] Gas logging and well logging response parameters were collated, and seven phase prediction indices were selected: acoustic time difference (DT), gamma value (GR), resistivity (R), gas logging value (Tg), gas logging value (C1), hydrocarbon moisture ratio (Wh), and the difference between the hydrocarbon moisture ratio (Wh) and the hydrocarbon equilibrium ratio (Bh). These seven phase prediction indices were standardized to obtain the standardized phase prediction indices. Furthermore, 475 sample points with known phase types were selected from Wells A and B.

[0092] The principal component analysis method was used to calculate the principal component I and principal component II of well A and well B respectively using the above principal component I calculation formula and principal component II calculation formula.

[0093] Based on 475 sample points, principal components I and II of well A, and principal components I and II of well B, a phase state prediction chart was established.

[0094] The classification standard of oil and gas phase types is determined based on the gas test response value of hydrocarbon components in oil and gas samples. The classification standard is superimposed on the phase prediction chart to form a phase prediction chart containing critical phase types (see Figure 5 ).

[0095] Figure 6 、 7 The figure shows the oil and gas phase type results of Well A identified using the phase prediction chart containing critical phase types. After point placement, the C layer of Well A was identified as a high-viscosity heavy oil reservoir, and the D layer was identified as a condensate gas reservoir without an oil ring.

[0096] Figure 8 The figure shows the oil and gas phase types of Well B, identified using a phase prediction chart containing critical phase types. After point placement, the E and F intervals of Well B were identified as condensate gas reservoirs with oil rings.

[0097] The above embodiments are used to explain the present application rather than to limit the present application. Any modifications and changes made to the present application within the spirit of the present application and the protection scope of the claims shall fall within the protection scope of the present application.

Claims

1. A method for identifying oil and gas phase types, characterized in that: The steps are: Obtain well logging data and mud logging data of the target layer in the study area; Select phase prediction indicators of the target layer in the study area based on well logging data, and select multiple sample points of known phase types of the target layer in the study area based on logging data; Calculate the principal component of the target formation according to the phase state prediction index, and establish a phase state prediction chart according to multiple sample points and principal component projection points, wherein the abscissa of the phase state prediction chart is principal component I, and the ordinate is principal component II; The classification standard of oil and gas phase types is determined based on the gas test response value of hydrocarbon components in oil and gas samples, and the classification standard is superimposed on the phase prediction plate to form a phase prediction plate containing critical phase types; The oil and gas phase types of the target layers in the study area are identified based on the phase prediction chart containing critical phase types.

2. The oil and gas phase type identification method according to claim 1, characterized in that: The phase state prediction indicators include acoustic time difference DT, gamma value GR, resistivity value R, gas measurement value Tg, gas measurement value C1, hydrocarbon moisture ratio Wh, and the difference between hydrocarbon moisture ratio Wh and hydrocarbon equilibrium ratio Bh.

3. The oil and gas phase type identification method according to claim 2, characterized in that: The acoustic time difference DT, gamma value GR, resistivity value R, gas logging value Tg, and gas logging value C1 are directly read from the well logging curve of the target layer in the study area; the hydrocarbon moisture ratio Wh and hydrocarbon balance ratio Bh are calculated based on the gas logging response values of the hydrocarbon components of the oil and gas samples; Where C1, C2, C3, C4, C5, iC4, nC4, iC5, and nC5 are the gas measurement response values of the corresponding hydrocarbon components.

4. The oil and gas phase type identification method according to claim 3, characterized in that: The method for calculating the principal components of the target stratum based on the phase prediction index is: The phase state prediction index is standardized to obtain a standardized phase state prediction index; Calculate principal component I and principal component II respectively; Principal component I = 0.27*A1-0.10*A2-0.22*A3+0.56*A4+0.56*A5-0.34*A6-0.34*A7 Principal component II = -0.61*A1+0.25*A2+0.65*A3+0.18*A4+0.21*A5-0.19*A6-0.13*A7 Wherein, A1 is the standardized acoustic time difference DT, A2 is the standardized gamma value GR, A3 is the standardized resistivity value R, A4 is the standardized gas measurement value Tg, A5 is the standardized gas measurement value C1, A6 is the standardized hydrocarbon moisture ratio Wh, and A7 is the difference between the standardized hydrocarbon moisture ratio Wh and the hydrocarbon balance ratio Bh.

5. The oil and gas phase type identification method according to claim 1, characterized in that: The method for distinguishing the classification standard of oil and gas phase types based on the gas test response value of hydrocarbon components in oil and gas samples is as follows: Calculated based on the gas test response value of hydrocarbon components in oil and gas samples φ 1 parameter; Where, C1, C2, C3, C4, C5 + are the gas measurement response values corresponding to the hydrocarbon components; According to the calculated φ 1 parameter to obtain the classification standard of oil and gas phase types.

6. The oil and gas phase type identification method according to claim 5, characterized in that: According to the calculated φ 1 parameter to obtain the classification standard of oil and gas phase types: φ When 1≤2.5, the oil and gas phase type is black oil. φ When 1≤1, the oil and gas phase type is high viscosity heavy oil reservoir, when 1< φ When 1≤2.5, the oil and gas phase type is ordinary black oil reservoir; when 2.5< φ When 1≤15, the oil and gas phase type is volatile oil, among which, when 2.5< φ When 1≤7, the oil and gas phase type is volatile oil reservoir, when 7< φ When 1≤15, the oil and gas phase type is condensate gas cap reservoir; when φ When 1>15, the oil and gas phase type is condensate gas. φ When 1≤80, the oil and gas phase type is a condensate gas reservoir with oil ring; when φ When 1>80, the oil and gas phase type is a condensate gas reservoir without oil ring.

7. An oil and gas phase type identification system, used to implement the oil and gas phase type identification method according to any one of claims 1 to 6, characterized in that: include: Acquisition module, used to obtain well logging data and mud logging data of the target layer in the study area; Selection module, which selects the phase state prediction index of the target layer in the study area based on the well logging data, and multiple sample points with known phase state types based on the logging data; A calculation module calculates the principal components of the target layer based on the phase prediction index; A chart construction module is used to build a phase prediction chart based on multiple sample points obtained and the calculated principal component projection points; The classification standard discrimination module determines the classification standard of oil and gas phase types based on the gas testing response value of hydrocarbon components in oil and gas samples; A superposition module superimposes the classification criteria on the phase state prediction plate to form a phase state prediction plate containing critical phase state types; The phase type identification module identifies the oil and gas phase type of the target layer in the study area based on the phase prediction map containing critical phase types.

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