Reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging chart

Abstract

The invention provides a reservoir fluid identification method based on a three-dimensional quantitative fluorescence and gas logging chart, and belongs to the technical field of oil exploration drilling and logging interpretation and evaluation. The method comprises the following steps: determining an average value of total hydrocarbon values of a chromatographic gas logging pure mudstone section in a detected stratum depth range as a base value; calculating a gas logging anomaly multiple; in the three-dimensional quantitative fluorescence logging analysis data, determining equivalent oil content values and comparison level parameters in the same depth range as gas logging abnormity in chromatographic gas logging; establishing two interpretation charts of the two-dimensional space; and respectively carrying out plumbing on the two interpretation charts, and judging the reservoir fluid property according to a plumbing area. According to the method, the parameters of the two logging methods and the correlation of the parameters are comprehensively utilized, the multiplicity of solutions generated by errors of a single logging method is effectively reduced, and the fluid identification accuracy is improved.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum exploration drilling, logging interpretation and evaluation, and in particular to a reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts. Background Art

[0002] Due to the high costs and expenses of offshore drilling, the ability to quickly and effectively identify fluid properties during drilling plays a key role in decision-making. Mud logging technology can accurately identify fluid type and properties. Existing logging methods for fluid type identification mainly include gas logging, geochemical logging, and quantitative fluorescence logging.

[0003] Gas logging distinguishes oil and gas reservoirs by correlating the composition and abundance of hydrocarbon gases detected at the surface with the fluids in the subsurface reservoir. Gas logging is significantly influenced by drilling fluid. During drilling, various chemical additives, such as surfactants and lubricants, are often added to the drilling fluid to meet different operational requirements. These additives may release hydrocarbon gases, interfering with the gas logging's ability to detect true hydrocarbon gases in the formation. This can lead to deviations in the detected hydrocarbon gas composition and abundance, making it difficult to accurately assess the properties of the subsurface reservoir fluid. Fluctuations in formation pressure can also affect gas logging results. When drilling into high-pressure formations, gas from the formation may surge into the drilling fluid, causing abnormally high gas logging values. Conversely, in low-pressure formations, gas escape is difficult, and gas logging values may be low. These pressure fluctuations lead to high ambiguity in gas logging data, making it difficult to accurately reflect the true state of the reservoir fluid.

[0004] Geochemical logging involves producing hydrocarbon chromatograms to identify fluid types, and the sample processing process for geochemical logging is relatively complex. After obtaining rock cuttings or core samples, they need to go through multiple processes such as crushing and extraction before subsequent hydrocarbon chromatograms can be produced. This not only consumes a lot of time and manpower, but also during the sample processing process, it is easy for improper operation to cause sample contamination or component loss, affecting the accuracy of the analysis results. Geochemical logging analysis takes a long time, and it often takes hours or even days from sample collection to the final analysis results. In time-sensitive operations such as offshore drilling, this long analysis cycle cannot meet the needs of real-time decision-making, which may result in missing the best drilling operation time and increasing drilling costs.

[0005] Three-dimensional quantitative fluorescence logging uses fluorescence spectrum data and derived parameters to identify fluid types, based on the proportional relationship between fluorescence intensity and crude oil concentration. This effectively addresses some of the challenges of conventional fluorescence logging, such as fluorescence that cannot be identified visually and is subject to human influence. However, due to significant differences in crude oil quality across different formations, advances in drilling technology have led to severe fragmentation and reduced representativeness of rock cuttings, and the addition of organic solvents to drilling fluids, conventional logging complicates oil and gas identification.

[0006] When exposed to ultraviolet light, oil and asphaltene, components of petroleum, can emit a distinctive glow, a phenomenon known as oil fluorescence. This characteristic of oil is often manifested in differences in brightness and color. The brightness of the fluorescence can be used to determine the oil content, while the color of the emitted light can be used to determine the oil composition. Fluorescence logging is a highly intuitive and practical technology used in oil and gas field exploration and development. The development of fluorescence logging technology can be divided into two phases: the qualitative observation phase (from the 1950s to the present), using conventional fluorescence detectors, typified by fluorescent lamps; and the quantitative analysis phase (from the 1990s to the present), using quantitative fluorescence detectors, typified by the QFT one-dimensional fluorescence analyzer, the OFA, the QFA series two-dimensional, and the QFA series three-dimensional quantitative fluorescence analyzers. Three-dimensional quantitative fluorescence analyzers utilize multi-point excitation and multi-point reception, producing three-dimensional stereograms and isovalue maps. These analyzers provide a wealth of spectral data, making qualitative and quantitative analysis easier, and have gradually replaced two-dimensional quantitative fluorescence logging in field applications.

[0007] The principle of a three-dimensional quantitative fluorescence analysis system is that when a substance is in dilute solution and at low concentration, the fluorescence intensity of the measured sample is linearly and directly proportional to the concentration. However, when the concentration is too high, nonlinearity occurs, and at even higher concentrations, "quenching" occurs. Its key parameters include fluorescence wavelength, crude oil fluorescence intensity, equivalent oil content, contrast level, oiliness index, and porosity parameters. These parameters have a corresponding relationship and can be used to map crude oil and fluid properties. Advances in logging while drilling (LWD) methods, particularly the widespread use of three-dimensional quantitative fluorescence logging, have provided a convenient method for preliminary identification of fluid and crude oil properties in the field. However, due to the numerous influencing factors of single-item three-dimensional quantitative fluorescence logging, uncertainty can also arise. Single-item LWD chromatographic gas logging is a commonly used logging method in drilling, but it also has numerous influencing factors, often leading to uncertainty and multiple solutions. Therefore, integrating data from multiple logging methods to effectively identify fluid properties during drilling will improve drilling efficiency, reduce costs, and provide a basis for early evaluation of oil and gas reservoirs.

[0008] Gas logging while drilling (LWD) measures the gas content and composition of gas entering the drilling fluid due to rock fragmentation during drilling. It uses gas chromatography to analyze the various components (primarily C1 to C5) in natural gas. Due to the high cost and difficulty of offshore drilling, core and wall core sampling is not necessary. Therefore, 3D quantitative fluorescence logging, along with rock fragment and gas logging, is a must-have for LWD.

[0009] Many methods have traditionally used single-item logging techniques to identify oil and gas reservoir and fluid properties. However, considering only a single logging parameter is overly simplistic, and its accuracy is affected by environmental and instrumental factors. Specifically, the following are the main issues: 1. Different logging technologies are developed by different research teams or companies, each adhering to distinct technical standards and specifications. Gas logging focuses on hydrocarbon gas detection, with data acquisition frequency and accuracy standards centered around gas analysis; 3D quantitative fluorescence logging focuses on fluorescence parameter measurement, with standards prioritizing fluorescence signal processing. In practice, the lack of unified standards makes it difficult to match the data collected by the two technologies in terms of time scale, measurement unit, and data accuracy, making direct integration and analysis impossible. This limits the combined application of multiple logging methods. 2. The hardware and software design of logging equipment is highly specialized. Gas logging equipment is based on gas chromatography principles and has a complex structure, with specialized gas sampling, separation, and detection modules. 3D quantitative fluorescence logging equipment is built around fluorescence detection, with unique optical systems and signal acquisition and processing components. The two devices are incompatible in terms of interface design and data transmission protocols, preventing real-time data exchange and sharing. Moreover, the supporting analysis software is not universal and the data formats are different, making it difficult to import data from different devices into the same platform for comprehensive analysis, which hinders the integration of technologies. 3. Individual logging technologies have formed their own data processing methods and models. Gas logging uses statistical analysis, trend prediction and other methods to determine the properties of reservoir fluids based on the changes in gas components. Three-dimensional quantitative fluorescence logging uses parameters such as fluorescence intensity and wavelength, and adopts spectral analysis and pattern recognition technology. Due to the large differences in processing ideas and algorithms, data from different technologies are difficult to integrate and process. If forced to integrate, it will be impossible to effectively extract valuable information due to conflicts in data processing methods, making it difficult to give full play to the advantages of comprehensive logging, which limits the application of combined technologies. Summary of the Invention

[0010] In view of this, the present invention aims to propose a reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts. In the absence of logging data or delayed interpretation of logging data, this method can accelerate the identification of formation fluid properties, make timely and rapid next-step decisions, and reduce production costs. This method can provide a basis for drilling operations and drilling deployment during the drilling process, and guide marine oil drilling work.

[0011] To achieve the above object, the technical solution of the present invention is implemented as follows: a reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts, comprising the following steps:

[0012] Determine the average value of total hydrocarbon value of pure mudstone section in the chromatographic gas logging within the depth range of the detected formation as the base value;

[0013] The depth section higher than the base value is the gas logging abnormal section. First, calculate the average value of the total hydrocarbon value of the gas logging abnormal section, and then calculate the gas logging abnormal multiple;

[0014] In the 3D quantitative fluorescence logging analysis data, read the equivalent oil content value and comparison level parameters in the same depth range as the gas logging anomaly in the chromatographic gas logging;

[0015] Establish two two-dimensional interpretation maps; including establishing a two-dimensional interpretation map using the gas logging anomaly multiple and the equivalent oil content value, and establishing a two-dimensional interpretation map using the gas logging anomaly multiple and the comparison level parameter;

[0016] Points are projected on two interpretation plates respectively, and the reservoir fluid properties are determined based on the projected areas.

[0017] Furthermore, the calculation formula for the gas logging anomaly multiple is: P = Tgmax / Tgmin, where Tgmax is the average value of the total hydrocarbon value of the gas logging anomaly section, and Tgmin is the average value of the total hydrocarbon value of the pure mudstone section of the chromatographic gas logging.

[0018] Furthermore, equivalent oil content refers to the hydrocarbon content determined after comparison with a standard oil sample, which is used to indicate the relative abundance of hydrocarbons in the reservoir fluid; the contrast level parameter refers to a parameter that measures the difference between the fluorescence signal intensity and that of the standard oil sample, which is used to evaluate the type and properties of hydrocarbons in the reservoir fluid.

[0019] Furthermore, the interpretation map established using the gas logging anomaly multiple and the equivalent oil content value has its ordinate as the equivalent oil content value and its abscissa as the gas logging anomaly multiple; the interpretation map established using the gas logging anomaly multiple and the comparison level parameter has its ordinate as the comparison level parameter and its abscissa as the gas logging anomaly multiple.

[0020] Furthermore, the equivalent oil content and gas logging anomaly multiples obtained in the same depth range are projected onto the established two-dimensional space interpretation map, and the reservoir fluid properties are judged based on the projected area; the comparison level parameters and gas logging anomaly multiples obtained in the same depth range are projected onto the established two-dimensional space interpretation map, and the reservoir fluid properties are judged based on the projected area.

[0021] Compared with the existing technology, the reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts described in the present invention has the following advantages:

[0022] (1) The method of the present invention not only uses the equivalent oil content and comparison level parameters in the three-dimensional quantitative fluorescence logging parameters, but also uses the gas logging anomaly multiple in the gas logging. The correlation between the three-dimensional quantitative fluorescence logging parameters and the gas logging anomaly multiple in the gas logging is established, and on this basis, an identification chart is created. The comprehensive use of the parameters of the two logging methods and their correlation effectively reduces the multiplicity of errors caused by a single logging method and improves the accuracy of fluid identification.

[0023] (2) Compared with using only three-dimensional quantitative fluorescence logging parameters, the advantages of the present invention are as follows: a single three-dimensional fluorescence logging method is difficult to identify conventional logging oil and gas. The chromatographic gas logging parameter technology has the characteristics of a wide scanning range, high detection accuracy, and rich data and graph display types. The fluid properties can be quickly and accurately identified based on the on-site real-time three-dimensional quantitative fluorescence spectrum and parameters and the crude oil standard sample spectrum. Therefore, the comprehensive judgment of the three-dimensional quantitative fluorescence logging parameters combined with the chromatographic gas logging parameters is more reliable;

[0024] (3) In offshore oil exploration and other operational scenarios, time and exploration costs are crucial. The present invention utilizes three-dimensional quantitative fluorescence logging and gas logging parameters to establish an identification chart, which can quickly and accurately identify reservoir fluid properties. This enables explorers to make accurate judgments about the strata encountered during the drilling process. By reducing unnecessary exploration operations, the overall exploration efficiency is greatly improved, exploration costs are significantly saved, greater economic benefits are created for oil companies, and competitiveness in the oil exploration market is enhanced. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] The accompanying drawings, which constitute part of the present invention, are provided to provide a further understanding of the present invention. The exemplary embodiments of the present invention and their descriptions are provided to explain the present invention and do not constitute an undue limitation of the present invention. In the accompanying drawings:

[0026] Figure 1 This is a flow chart of a reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts according to an embodiment of the present invention;

[0027] Figure 2 This is a comprehensive diagram of gas logging while drilling chromatography;

[0028] Figure 3 It is a three-dimensional quantitative fluorescence and gas logging chart for identifying reservoir fluid properties; Figure 3 a is the intersection diagram of gas logging anomaly multiple and equivalent oil content, Figure 3 b is the intersection diagram of gas logging anomaly multiples and comparison levels. DETAILED DESCRIPTION

[0029] It should be noted that, in the absence of conflict, the embodiments of the present invention and the features in the embodiments may be combined with each other.

[0030] like Figure 1-Figure 3As shown, the present invention proposes a method for identifying reservoir fluid properties using parameters derived from the three-dimensional quantitative fluorescence spectrum of drilling cuttings and chromatographic gas logging parameters. Among them, the equivalent oil content and contrast level are parameters derived from the three-dimensional quantitative fluorescence spectrum of drilling cuttings. They are obtained by performing three-dimensional quantitative fluorescence analysis on cuttings samples collected while drilling. The equivalent oil content is the hydrocarbon content determined by comparison with a standard oil sample and is used to indicate the relative abundance of hydrocarbons in the reservoir fluid. The contrast level parameter measures the difference in fluorescence signal intensity compared with the standard oil sample and is used to assess the type and properties of hydrocarbons in the reservoir fluid. The total hydrocarbon anomaly multiple is a chromatographic gas logging parameter and is calculated using the formula (P = Tgmax / Tgmin), where Tgmax is the average total hydrocarbon value of the gas logging anomaly section and Tgmin is the average total hydrocarbon value of the chromatographic gas logging pure mudstone section. This parameter is used to measure the relative change in hydrocarbon gas content in the reservoir and assist in determining the fluid properties of the reservoir.

[0031] Specifically, the present invention is a method for identifying reservoir fluid properties using three-dimensional quantitative fluorescence and gas logging charts, comprising the following steps:

[0032] The average value of the total hydrocarbon value of the pure mudstone section of the chromatographic gas logging is determined as the base value within the main detection depth range. Specifically, within the main detection depth range, the mudstone section adjacent to the gas logging anomaly section is selected as the research object, and the average value of the total hydrocarbon (Tg) value in the chromatographic gas logging of the pure mudstone section is calculated, and this average value is used as the base value.

[0033] Depths above the base value are considered gas logging anomaly sections, and the ratio of the average total hydrocarbon value of the gas logging anomaly section to the base value is calculated, i.e., the gas logging anomaly multiple. Within the depth range of the detected formation, the average total hydrocarbon (Tg) parameter in the chromatographic gas logging of the pure mudstone section is first determined. Then, the sections within the depth range of the detected formation where gas logging anomalies occur are calculated, i.e., the sections where the total hydrocarbon (Tg) value is higher than the base value (the average total hydrocarbon value of the pure mudstone section). Finally, the gas logging anomaly multiple is calculated. The formula for calculating the gas logging anomaly multiple is: P = Tgmax / Tgmin, where Tgmax is the average total hydrocarbon value of the gas logging anomaly section, and Tgmin is the average total hydrocarbon value of the pure mudstone section in the chromatographic gas logging.

[0034] In the same depth range where the total hydrocarbon (Tg) value anomaly appears in the chromatographic gas logging, and in the three-dimensional quantitative fluorescence logging analysis data, the equivalent oil content value and comparison level parameter are read in the same depth range as the gas logging anomaly appears in the chromatographic gas logging. The equivalent oil content refers to the hydrocarbon content determined after comparison with the standard oil sample, which is used to express the relative abundance of hydrocarbons in the reservoir fluid. The comparison level parameter refers to the parameter that measures the difference between the fluorescence signal intensity and the standard oil sample, which is used to evaluate the type and nature of hydrocarbons in the reservoir fluid.

[0035] Parameters are derived from the analytical data of 3D quantitative fluorescence logging and chromatographic gas logging for logging while drilling. These parameters are key data used to create interpretation maps and identify reservoir fluid properties. Specifically, they fall into two categories: 1. Parameters from 3D quantitative fluorescence logging analysis data, such as equivalent oil content (hydrocarbon content determined by comparison with a standard oil sample) and comparison level parameters (the difference between fluorescence signal intensity and that of a standard oil sample); and 2. Parameters from chromatographic gas logging analysis data, such as gas logging anomaly multiples. Based on the equivalent oil content values, comparison level parameters, and gas logging anomaly values in the three-dimensional quantitative fluorescence logging analysis data while drilling obtained in the same depth range, two two-dimensional logging parameter interpretation maps are established to identify reservoir fluid properties; including establishing a two-dimensional interpretation map using the gas logging anomaly multiple and the equivalent oil content value, and establishing a two-dimensional interpretation map using the gas logging anomaly multiple and the comparison level parameter; wherein, the ordinate of the interpretation map established using the gas logging anomaly multiple and the equivalent oil content value is the equivalent oil content value, and the abscissa is the gas logging anomaly multiple; the ordinate of the interpretation map established using the gas logging anomaly multiple and the comparison level parameter is the comparison level parameter, and the abscissa is the gas logging anomaly multiple.

[0036] Points are projected onto two interpretation charts, and reservoir fluid properties are determined based on the projected areas. Specifically, the equivalent oil content and gas logging anomaly multiples obtained within the same depth range are projected onto the established two-dimensional interpretation chart, and reservoir fluid properties are determined based on the projected areas. Contrast level parameters and gas logging anomaly multiples obtained within the same depth range are projected onto the established two-dimensional interpretation chart, and reservoir fluid properties are determined based on the projected areas. It should be noted that different interpretation charts are established for different oilfield areas.

[0037] The present invention discloses a reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts. Within the main detected formation depth range, the average value of the total hydrocarbon (Tg) parameter in the chromatographic gas logging of the pure mudstone section is determined; the layer sections with gas logging anomalies within the detected formation depth range, that is, the layer sections with the average total hydrocarbon (Tg) value higher than the base value (the average total hydrocarbon value of the pure mudstone section), are calculated, and the gas logging anomaly multiple is calculated; within the same depth range where the total hydrocarbon (Tg) value anomalies appear in the chromatographic gas logging, the equivalent oil content and comparison level of the parameters are calculated in the three-dimensional quantitative fluorescence logging analysis data; the equivalent oil content, gas logging anomaly multiple, comparison level, and gas logging anomaly multiple obtained in the three-dimensional quantitative fluorescence analysis data within the same depth range are respectively projected onto a two-dimensional interpretation chart, and the reservoir fluid properties are determined based on the projected area. In the Beibu Gulf Basin and Zhusan Depression, this method has achieved over 92% agreement between reservoir identification and actual testing / pressure sampling using this chart, providing a simple and reliable method for rapid identification of fluid properties during drilling and logging. The method is simple to operate, parameters are readily available, and judgments are timely and accurate, demonstrating excellent prospects for application and widespread adoption.

[0038] The situation of no logging data or delayed interpretation of logging data often occurs, which seriously affects the efficiency of judging the properties of formation fluids. The reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts provided by the present invention has shown significant advantages in this case, and can quickly and efficiently identify the properties of formation fluids. During the drilling process, the chromatographic gas logging equipment while drilling will continuously and in real time monitor the gas that enters the drilling fluid due to the crushing of rock cuttings. Within the main detection formation depth range, the equipment can quickly determine the total hydrocarbon value of the pure mudstone section of the chromatographic gas logging and calculate its average value as the base value. Once a depth section higher than the base value appears, it is determined to be a gas logging abnormal section. The entire process is carried out almost synchronously with drilling, and there is no need to wait for logging data, which greatly saves time.

[0039] At the same time, 3D quantitative fluorescence logging equipment is also providing timely analysis of cuttings samples collected while drilling. Within the same depth range where the chromatographic gas logging anomaly occurs, the 3D quantitative fluorescence logging equipment can quickly determine the equivalent oil content and comparison level parameters. These parameters are acquired extremely quickly, minimizing the time from cuttings sample collection to analysis results, effectively avoiding delays caused by waiting for logging data.

[0040] Based on the real-time acquired gas logging anomaly multiples, equivalent oil content values, and comparison level parameters, two two-dimensional interpretation maps can be quickly created. The interpretation map created using gas logging anomaly multiples and equivalent oil content values has the equivalent oil content value on the ordinate and the gas logging anomaly multiples on the abscissa. The interpretation map created using gas logging anomaly multiples and comparison level parameters has the comparison level parameter on the ordinate and the gas logging anomaly multiples on the abscissa. In practice, once a new set of data is acquired, points can be immediately placed on these two interpretation maps. Based on the location of the points, reservoir fluid properties can be quickly determined, such as whether they are oil, water, or dry layers.

[0041] The present invention will be described in detail below with reference to the accompanying drawings and in conjunction with embodiments.

[0042] 1) If Figure 2 As shown in the figure, at the depth section where the total hydrocarbon value of the chromatographic gas test is abnormal (high value), the average value of the total hydrocarbon (Tg) of the gas test of the upper and lower mudstone sections is read in combination with Table 1 as the base value Tgmin;

[0043] Table 1. Chromatographic gas logging data while drilling

[0044]

[0045]

[0046]

[0047]

[0048] 2) If Figure 2 As shown, at the depth section where the chromatographic gas test total hydrocarbon value appears abnormal (high value), the average value Tgmax of the gas test total hydrocarbon (Tg) of the upper and lower gas test abnormal sections is read from Table 1;

[0049] 3) The chromatographic gas testing anomaly multiple primarily measures the relative change in hydrocarbon gas content in a reservoir. By calculating this anomaly multiple, it is possible to more effectively identify whether the fluid in a reservoir is oil, gas, or water. This can more effectively assist in determining the fluid properties of the reservoir and more quickly identify potential reservoirs.

[0050] Calculate the chromatographic gas logging anomaly multiple, P = Tgmax / Tgmin; actual drilling experience in oil fields shows that the larger the gas logging anomaly multiple, the higher the hydrocarbon content of the fluid.

[0051] 4) In the 3D quantitative fluorescence logging analysis data, read the equivalent oil content value and comparison level parameters of the same depth section as the gas logging anomaly in the chromatographic gas logging in Table 2.

[0052] Table 2 Parameter data of three-dimensional quantitative fluorescence analysis

[0053]

[0054]

[0055]

[0056] 5) Collect fluid property samples verified by testing or pressure sampling, and read the equivalent oil content and comparison level parameters of the chromatographic gas logging anomaly multiple and the three-dimensional quantitative fluorescence logging analysis data;

[0057] 6) Use the obtained sample data to create an interpretation chart; Figure 3 As shown in a, the ordinate of the interpretation chart is the equivalent oil content, and the abscissa is the gas logging anomaly multiple. According to the distribution of a large number of sampling points of reservoirs with different fluid properties in two-dimensional space, the two-dimensional space is divided into water layer dry layer area and oil layer / oil and water layer area. Figure 3 As shown in b, the vertical axis of the interpretation chart is the comparison level, and the horizontal axis is the gas logging anomaly multiple. According to the distribution of a large number of points in the two-dimensional space of reservoirs with different fluid properties, the two-dimensional space is divided into water layer dry layer area and oil layer / oil and water layer area. Figure 3 From a and 3b, we can see that when the gas logging anomaly multiple is >3, the equivalent oil content is >20mg / L, and the comparison level is >6, it is an oil layer; when the gas logging anomaly multiple is <3, the equivalent oil content is <40mg / L, and the comparison level is <6, it is a water layer and a dry layer.

[0058] 7) Project points on the chart to determine the reservoir fluid properties.

[0059] For example, a well in the W17-A oilfield in the Wushi Sag detected fine sandstone in the third section of the Liuliu Formation. The gas logging anomaly multiple was 3.82, with an equivalent oil content of 32mg / L-83mg / L and a contrast level parameter of 6.3-8.1. Actual data from this well showed a gas logging anomaly multiple >3, a contrast level >6, and an equivalent oil content >20mg / L. Based on these three parameters, the well's corresponding parameters met the criteria for oil-bearing formations. Therefore, the interpretation chart determined this interval to be an oil-bearing formation. Pressure sampling was conducted within this interval, and a 300ml oil sample was obtained at 2467.5m, validating the interpretation chart's judgment.

[0060] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging charts, characterized in that: The following steps are involved: Determine the average value of total hydrocarbon value of pure mudstone section in the chromatographic gas logging within the depth range of the detected formation as the base value; The depth section higher than the base value is the gas logging abnormal section. First, calculate the average value of the total hydrocarbon value of the gas logging abnormal section, and then calculate the gas logging abnormal multiple; In the 3D quantitative fluorescence logging analysis data, read the equivalent oil content value and comparison level parameters in the same depth range as the gas logging anomaly in the chromatographic gas logging; Establish two explanatory plates of two-dimensional space; This includes establishing a two-dimensional interpretation chart using the gas logging anomaly multiples and equivalent oil content values, and establishing a two-dimensional interpretation chart using the gas logging anomaly multiples and comparison level parameters; Points are projected on two interpretation plates respectively, and the reservoir fluid properties are determined based on the projected areas.

2. The reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging chart according to claim 1, characterized in that: The calculation formula of the gas logging anomaly multiple is: P = Tgmax / Tgmin, where Tgmax is the average value of the total hydrocarbon value of the gas logging anomaly section, and Tgmin is the average value of the total hydrocarbon value of the pure mudstone section of the chromatographic gas logging.

3. The reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging chart according to claim 1, characterized in that: Equivalent oil content refers to the hydrocarbon content determined after comparison with a standard oil sample, which is used to indicate the relative abundance of hydrocarbons in the reservoir fluid. The contrast level parameter refers to the parameter that measures the difference between the fluorescence signal intensity and that of the standard oil sample, which is used to evaluate the type and properties of hydrocarbons in the reservoir fluid.

4. The reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging chart according to claim 1, characterized in that: The interpretation chart established using the gas logging anomaly multiple and the equivalent oil content value has its ordinate as the equivalent oil content value and its abscissa as the gas logging anomaly multiple; the interpretation chart established using the gas logging anomaly multiple and the comparison level parameter has its ordinate as the comparison level parameter and its abscissa as the gas logging anomaly multiple.

5. The reservoir fluid identification method based on three-dimensional quantitative fluorescence and gas logging chart according to claim 4, characterized in that: The equivalent oil content and gas logging anomaly multiples obtained in the same depth range are projected onto the established two-dimensional space interpretation map, and the reservoir fluid properties are judged based on the projected area; the comparison level parameters and gas logging anomaly multiples obtained in the same depth range are projected onto the established two-dimensional space interpretation map, and the reservoir fluid properties are judged based on the projected area.

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