A method for judging fluid properties based on real-time carbon isotope logging technology

Abstract

The application discloses a method for judging fluid properties based on real-time carbon isotope logging technology, which comprises the following steps: step one, obtaining isotope parameters and judging the type of oil and gas reservoir fluid; step two, establishing an analysis chart and judging the oil and gas charging degree; step three, establishing the methane isotope ratio of reservoir and cap rock and judging the oil and gas preservation condition; and step four, determining the storage fluid properties according to the type of oil and gas reservoir fluid, the charging degree and the preservation condition. The carbon isotope data are obtained through the real-time carbon isotope logging technology, and the established fluid charging degree analysis chart is combined, so that the complex fluid property problems which are difficult to implement by using the existing gas logging, geochemical logging, cutting fluorescence logging and other logging technologies can be supplemented, and the accuracy of fluid property judgment is further improved, and a more reliable discrimination method is provided for oil exploration and development.

Description

Technical Field

[0001] This invention relates to the field of petroleum exploration and development technology, and in particular to a method for determining fluid properties based on real-time carbon isotope logging technology. Background Technology

[0002] Well logging is a process that uses methods such as rock and mineral analysis, geophysics, and geochemistry to observe, collect, record, and analyze information on solid, liquid, and gaseous materials returned from the wellbore during the drilling process. This information is used to establish well logging geological profiles, discover oil and gas shows, evaluate oil and gas reservoirs, and provide drilling information services for petroleum engineering (investors, drilling engineers, and other engineering projects). Well logging technology is the most basic technology in oil and gas exploration and development activities. It is the most timely and direct means of discovering and evaluating oil and gas reservoirs, and it has the characteristics of timely and diverse acquisition of underground information and rapid analysis and interpretation.

[0003] With the increasing complexity of deep-water and deep-seated oil and gas exploration targets at sea, conventional logging and well logging techniques for evaluating oil and gas, including gas logging, geochemical logging, cuttings fluorescence logging, and logging-while-drilling resistivity, density, and neutron logging techniques, are insufficient to evaluate the fluid properties of reservoirs. This poses a significant challenge to exploration and development decisions and the confirmation and submission of regional reserves. Therefore, this invention proposes a method for determining fluid properties based on real-time carbon isotope logging technology to solve the problems existing in the prior art. Summary of the Invention

[0004] To address the aforementioned problems, the present invention aims to propose a method for determining fluid properties based on real-time carbon isotope logging technology. This method acquires carbon isotope data through real-time carbon isotope logging and combines it with an established fluid charge analysis chart. This method can supplement existing logging techniques such as gas logging, geochemical logging, and cuttings fluorescence logging, which are difficult to use to determine complex fluid properties. This further improves the accuracy of fluid property determination and provides a more reliable identification method for oil exploration and development.

[0005] To achieve the objectives of this invention, the invention is implemented through the following technical solution: a method for determining fluid properties based on real-time carbon isotope logging technology, comprising the following steps:

[0006] Step 1: Isotope parameter acquisition. Real-time carbon isotope logging technology is used to acquire methane and ethane carbon isotope parameters. Gas logging technology is used to obtain gas logging derived parameters. Combined with the parameters, the fluid type of the oil and gas reservoir is determined.

[0007] Step 2: Establishment of analysis charts. Use real-time carbon isotope logging technology to obtain isotope parameters to establish fluid injection degree analysis charts, and determine the degree of oil and gas injection based on the analysis charts.

[0008] Step 3: Determine the fluid properties. Based on the methane carbon isotope and ethane carbon isotope parameters, establish the methane carbon isotope ratio η of the reservoir and caprock to evaluate the effectiveness of the reservoir and caprock, and determine the oil and gas preservation conditions.

[0009] Step 4: Analyze and judge the reservoir fluid type, oil and gas filling degree and oil and gas preservation conditions, and combine the water saturation predicted by isotopes to finally determine the reservoir fluid properties.

[0010] The further improvement lies in the fact that the establishment of the fluid filling degree analysis chart in step two specifically includes:

[0011] S1. Obtain carbon isotope parameter values ​​for methane, ethane, and propane using real-time carbon isotope logging technology;

[0012] S2. Establish oil and gas charging trend areas by utilizing high-quality gas reservoirs with proven high oil and gas charging levels in the region;

[0013] S3. Establish a region with low maturity trend of local shallow source rocks;

[0014] S4. Determine the degree of oil and gas injection based on the trend of carbon isotope parameter values ​​falling within S2 and S3.

[0015] Further improvements are made in the following ways: In S4, the specific judgment result is that when the layer falls in a high-quality gas layer area with a high degree of oil and gas filling, the deep oil and gas filling degree is high and the fluid properties are gas layers with high hydrocarbon saturation; when the layer falls in a local shallow source rock area with a low maturity trend, the deep oil and gas filling degree is low and the fluid properties are gas-water layers with low hydrocarbon saturation.

[0016] A further improvement is made in the following formula for calculating the methane carbon isotope ratio η in step three:

[0017]

[0018] Where m represents the maximum value of methane carbon isotopes in the reservoir, and n represents the average value of isotopes in the overlying layer at 100m.

[0019] A further improvement is made in the following step: when judging the oil and gas preservation conditions in step three, the smaller the methane carbon isotope ratio η of the reservoir and caprock, the fluid properties are gas layers with low water saturation; the larger the methane carbon isotope ratio η of the reservoir and caprock, the fluid properties are gas-water layers with high water saturation.

[0020] A further improvement is that, in step four, when using isotopes to predict water saturation, the smaller the methane-carbon isotope ratio of the reservoir caprock, the lower the water saturation, and vice versa.

[0021] The further improvement lies in the fact that the determination of reservoir fluid properties in step four provides results from two aspects: the type of oil and gas injected and the hydrocarbon saturation. The fluid properties include condensate gas layers, oil-type gas layers, biogas layers, coal-type gas layers, and gas-bearing water layers.

[0022] The beneficial effects of this invention are as follows: This invention obtains carbon isotope data through real-time carbon isotope logging technology, and combines it with the established fluid filling degree analysis chart. This can supplement the complex fluid property problems that are difficult to solve using existing logging technologies such as gas logging, geochemical logging, and cuttings fluorescence logging, thereby further improving the accuracy of fluid property judgment and providing a more reliable discrimination method for oil exploration and development. Attached Figure Description

[0023] Figure 1 This is a flowchart of the method in Embodiment 1 of the present invention.

[0024] Figure 2 This is a diagram illustrating the method architecture of Embodiment 1 of the present invention.

[0025] Figure 3 This is a graph showing the correlation between the methane carbon isotope ratio and water saturation in the reservoir caprock of Embodiment 1 of the present invention.

[0026] Figure 4 This is an explanatory diagram of the carbon isotopes of methane and the gaseous components C1 / (C2+C3) in Example 2 of the present invention.

[0027] Figure 5 This is an explanatory diagram of the carbon isotopes of methane and ethane in Example 2 of the present invention.

[0028] Figure 6 This is a diagram illustrating the determination of fluid properties based on the C1 anomaly factor and resistivity in Embodiment 2 of the present invention.

[0029] Figure 7 This is an explanatory diagram of the carbon isotopes of ethane and methane in Example 2 of the present invention.

[0030] Figure 8 This is a graph for judging fluid properties based on the Tg anomaly multiple and the C1 anomaly multiple in Embodiment 2 of the present invention. Detailed Implementation

[0031] To enhance understanding of the present invention, the present invention will be further described in detail below with reference to embodiments. These embodiments are only used to explain the present invention and do not constitute a limitation on the scope of protection of the present invention.

[0032] Example 1

[0033] according to Figure 1 , Figure 2 and Figure 3As shown, this embodiment provides a method for determining fluid properties based on real-time carbon isotope logging technology, including the following steps:

[0034] Step 1: Isotope parameter acquisition. Real-time carbon isotope logging technology is used to acquire methane and ethane carbon isotope parameters. Gas logging technology is used to obtain gas logging derived parameters. Combined with the parameters, the fluid type of the oil and gas reservoir is determined.

[0035] Step 2: Establishment of analysis charts. Use real-time carbon isotope logging technology to obtain isotope parameters to establish fluid injection degree analysis charts, and determine the degree of oil and gas injection based on the analysis charts.

[0036] The establishment of the fluid filling degree analysis chart specifically includes:

[0037] S1. Obtain carbon isotope parameter values ​​for methane, ethane, and propane using real-time carbon isotope logging technology;

[0038] S2. Establish oil and gas charging trend areas by utilizing high-quality gas reservoirs with proven high oil and gas charging levels in the region;

[0039] S3. Establish a region with low maturity trend of local shallow source rocks;

[0040] S4. Determine the degree of oil and gas injection based on the trend region where the carbon isotope parameter values ​​fall within S2 and S3.

[0041] Specifically, when the formation falls within a high-quality gas reservoir with a high degree of oil and gas filling, the deep oil and gas filling is high, and the fluid properties are gas reservoirs with high hydrocarbon saturation; when the formation falls within a region with a low maturity trend of local shallow source rocks, the deep oil and gas filling is low, and the fluid properties are gas-water reservoirs with low hydrocarbon saturation.

[0042] Step 3: Determining fluid properties. Based on the methane and ethane carbon isotope parameters, establish the methane carbon isotope ratio η of the reservoir and caprock to evaluate the effectiveness of the reservoir and caprock, and determine the oil and gas preservation conditions. When determining the oil and gas preservation conditions, the smaller the methane carbon isotope ratio η of the reservoir and caprock, the fluid properties are gas layers with low water saturation; the larger the methane carbon isotope ratio η of the reservoir and caprock, the fluid properties are gas-bearing water layers with high water saturation.

[0043] The formula for calculating the methane carbon isotope ratio η of the central reservoir caprock is as follows:

[0044]

[0045] Where m represents the maximum value of methane carbon isotopes in the reservoir, and n represents the average value of isotopes in the overlying layer at 100m.

[0046] The methane carbon isotope ratio of the reservoir and caprock shows a very strong correlation with water saturation, with a correlation coefficient of 0.93. A lower methane carbon isotope ratio corresponds to lower water saturation, as indicated in the appendix to the specification. Figure 3 As shown in the figure. Therefore, water saturation can be predicted using the methane carbon isotopes of the reservoir and caprock. The methane carbon isotope ratio of the reservoir and caprock reflects the effectiveness of the caprock; the smaller the ratio, the better the caprock's sealing performance and the lower the water saturation, and vice versa.

[0047] Step 4: Analyze and judge based on the reservoir fluid type, oil and gas charging degree, and oil and gas preservation conditions. At the same time, combine the water saturation predicted by isotopes. The smaller the methane carbon isotope ratio of the reservoir caprock, the lower the water saturation, and vice versa. Finally determine the reservoir fluid properties from the two aspects of charging oil and gas type and hydrocarbon saturation. Fluid properties include condensate gas layer, oil-type gas layer, biogenic gas layer, coal-type gas layer, and gas-bearing water layer.

[0048] This method for determining fluid properties based on real-time carbon isotope logging technology first uses conventional logging and survey data to determine whether the abundance of oil and gas can preliminarily determine the fluid properties. If the hydrocarbon abundance is high but the fluid phase is complex and difficult to identify, real-time carbon isotope logging technology is used to determine the type of oil and gas charging fluid. If it is difficult to determine the abundance of oil and gas using conventional logging and survey data, real-time carbon isotope logging technology is used to determine the degree of oil and gas charging and caprock sealing conditions, and finally determine the fluid properties.

[0049] Example 2

[0050] according to Figures 4-8 As shown, this embodiment provides specific implementation steps for a method to determine fluid properties based on real-time carbon isotope logging technology:

[0051] I. Utilize real-time carbon isotope technology to analyze the fluid types of injected oil and gas, and determine the properties of complex fluids.

[0052] According to conventional logging data such as gas logging and geochemical logging, the fluid in a certain structural reservoir has a high hydrocarbon abundance, but the fluid is in a critical phase and the fluid type is complex and difficult to identify.

[0053] Compared to the same reservoir in well A, well B exhibits less pronounced cuttings fluorescence characteristics, lower geochemical pyrolysis values, and no abnormalities observed in the n-alkane peaks of pyrolysis chromatography. Furthermore, the C1 percentage content of conventional gas analysis components is higher, as indicated in the attached instructions. Figure 4 As shown, well B exhibits critical state gas-biased characteristics, while well A exhibits oil-phase characteristics. The logging resistivity values ​​are similar, and the neutron density overlaps without significant differences, indicating no obvious difference in oil and gas characteristics. Further investigation is needed to determine the fluid phase type of well B.

[0054] Using real-time carbon isotope logging technology and methane carbon isotope and gas composition C1 / (C2+C3) charts, the target layer in Well B falls within the condensate-associated gas and coal-type gas region, as shown in the attached manual. Figure 5 As shown, to further distinguish between oil-type gas and coal-type gas, methane and ethane carbon isotope charts were used, ultimately confirming that the target layer was associated gas from condensate, as shown in the attached instruction manual. Figure 7 As shown.

[0055] Isotope logging technology determined that the target formation in well B was associated with condensate oil and gas. Final sampling confirmed the presence of condensate gas, with a gas-oil ratio of 1391.8 m³. 3 / m 3 This confirms the reliability of the isotope interpretation conclusion.

[0056] 2. Utilize real-time carbon isotope technology to analyze the degree of oil and gas filling and determine the properties of complex fluids.

[0057] Typical logging and measurement data for a high-quality gas reservoir in a certain area are characterized by high gas anomalies, high C1 percentage, high resistivity, and well-developed gas morphology. A certain well has two reservoirs; the upper reservoir (Series 1) meets the characteristics of a gas reservoir, while the lower reservoir (Series 2) falls into a poor-quality gas reservoir, very similar to a high-quality gas reservoir. However, the fluid properties are questionable and require further investigation, as detailed in the attached document. Figure 6 As shown.

[0058] An isotopic hydrocarbon filling degree identification chart was established. This chart shows that Layer 1 is similar to a high-quality gas layer in the region, with hydrocarbon maturity higher than that of the local mudstone, exhibiting characteristics of strong deep-seated, highly mature gas filling. Layer 2, on the other hand, has hydrocarbon maturity similar to the mudstone above and below it, as shown in the appendix to the instruction manual. Figure 7 As shown, although the reservoir has certain gas layer anomalies, the degree of deep high-maturity gas filling is low. Therefore, the fluid properties of layer 2 are confirmed to be gas-bearing water layer, and the sample is indeed a gas-bearing water layer, which confirms the reliability of the isotope conclusion.

[0059] Third, utilize real-time carbon isotope technology to analyze oil and gas preservation conditions and determine the properties of complex fluids.

[0060] Well A shows significant gas logging anomalies in the target formation. The gas logging components, absolute values, and anomaly multiples all meet the regional upper gas layer interpretation criteria. However, pressure testing confirms it is a water layer, specifically a high-gas-logging water layer. Determining the reserves in this area presents a considerable challenge, as detailed in the appendix to the specification. Figure 8 As shown.

[0061] In Well A, the structural zone comprises diapirs, sand bodies, and faults, forming a highly efficient migration system. Adjacent wells along the same migration path exhibit gas-bearing formations, indicating potential for reservoir formation in the target area. In adjacent well B, the target reservoir's caprock has a methane carbon isotope ratio of 0.83, indicating good caprock sealing. The predicted water saturation is 58.2%, suggesting a gas-bearing fluid. Well logging calculations show a water saturation of 57.4%, further confirming a gas-bearing formation. In contrast, Well A's target reservoir has a methane carbon isotope ratio of 0.94, with a predicted water saturation of 99.1%, indicating poor caprock sealing and a water-bearing fluid. Well logging calculations show a water saturation as high as 91.9%, also confirming a water-bearing formation. The isotopic interpretations are consistent with the actual results, demonstrating that isotopic logging technology can accurately determine reservoir fluid properties.

[0062] The foregoing has shown and described the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely illustrative of the principles of the invention. Various changes and modifications can be made to the invention without departing from its spirit and scope, and all such changes and modifications fall within the scope of the present invention as claimed. The scope of protection of the present invention is defined by the appended claims and their equivalents.

Claims

1. A method for determining fluid properties based on real-time carbon isotope logging technology, characterized in that, Includes the following steps: Step 1: Isotope parameter acquisition. Real-time carbon isotope logging technology is used to acquire methane and ethane carbon isotope parameters. Gas logging technology is used to obtain gas logging derived parameters. Combined with the parameters, the fluid type of the oil and gas reservoir is determined. Step 2: Establishment of analysis charts. Use real-time carbon isotope logging technology to obtain isotope parameters to establish fluid injection degree analysis charts, and determine the degree of oil and gas injection based on the analysis charts. Step 3: Determine the fluid properties. Based on the carbon isotope parameters of methane and ethane, establish the methane carbon isotope ratio η of the reservoir and caprock to evaluate the effectiveness of the reservoir and caprock and determine the oil and gas preservation conditions. Step 4: Analyze and judge the reservoir fluid type, oil and gas filling degree and oil and gas preservation conditions, and combine the water saturation predicted by isotopes to finally determine the reservoir fluid properties. When using isotopes to predict water saturation, the smaller the methane-carbon isotope ratio of the reservoir caprock, the lower the water saturation, and vice versa.

2. The method for determining fluid properties based on real-time carbon isotope logging technology according to claim 1, characterized in that: The establishment of the fluid filling degree analysis chart in step two specifically includes: S1. Obtain carbon isotope parameter values ​​for methane, ethane, and propane using real-time carbon isotope logging technology; S2. Establish oil and gas charging trend areas by utilizing high-quality gas reservoirs with proven high oil and gas charging levels in the region; S3. Establish a region with low maturity trend of local shallow source rocks; S4. Determine the degree of oil and gas injection based on the trend of carbon isotope parameter values ​​falling within S2 and S3.

3. The method for determining fluid properties based on real-time carbon isotope logging technology according to claim 2, characterized in that: The specific judgment result in S4 is as follows: when it falls in a high-quality gas layer area with a high degree of oil and gas filling, the deep oil and gas filling degree is high and the fluid properties are gas layers with high hydrocarbon saturation; when it falls in a local shallow source rock low maturity trend area, the deep oil and gas filling degree is low and the fluid properties are gas-water layers with low hydrocarbon saturation.

4. The method for determining fluid properties based on real-time carbon isotope logging technology according to claim 1, characterized in that: The formula for calculating the methane carbon isotope ratio η of the reservoir caprock in step three is as follows: ; Where m represents the maximum value of methane carbon isotopes in the reservoir, and n represents the average isotope value of the upper overburden layer over 100m.

5. The method for determining fluid properties based on real-time carbon isotope logging technology according to claim 1, characterized in that: In step four, the reservoir fluid properties are determined by the type of oil and gas injected and the hydrocarbon saturation. The fluid properties include condensate gas layers, oil-type gas layers, biogas layers, coal-type gas layers, and gas-bearing water layers.

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