Methods, apparatus, equipment and storage media for fluid identification in dense sandstone with high bound water

Abstract

This invention provides a method, apparatus, equipment, and storage medium for fluid identification in high-bound-water tight sandstone, relating to the technical field of oil and gas reservoir development equipment. The method includes: calculating water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on well logging data; comparing the water-bearing and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing and gas-bearing indicator parameters to determine the formation type of the target formation. Based on the technical solution of this invention, using water-bearing and gas-bearing indicator parameters to determine the type of the target formation increases the identification index of water response in high-bound-water tight sandstone, more effectively identifying fluids, thereby determining whether the high-bound-water tight sandstone reservoir has economic productivity, improving the success rate of reservoir fracturing operations, or accurately identifying oil and gas layers with economic productivity.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir development equipment technology, and particularly to a method, apparatus, equipment and storage medium for identifying fluids in tight sandstone with high bound water. Background Technology

[0002] Traditional logging techniques often rely on formation resistivity to identify fluids. However, for tight sandstone reservoirs, the complexity of lithology and pore structure means that resistivity measurements are influenced by many factors, leading to significant errors when relying solely on resistivity to identify fluids.

[0003] Acoustic wave, density, and neutron porosity logging curves are collectively known as the three-porosity logging curves, which are commonly used to estimate formation porosity. Researchers have later developed methods to identify gas-bearing layers using the differences in these three-porosity curves, primarily based on the principle that natural gas increases acoustic transit time, decreases density, and reduces neutron concentration. Currently, there are many studies on gas-bearing layer identification based on three-porosity logging data. Qualitative identification mainly utilizes the superposition of neutron, acoustic, and density curves for fluid identification. Quantitative identification primarily involves calculating the difference and ratio of the three porosities, then using these differences and ratios to create relevant cross-plots for gas layer identification, or further constructing coincidence parameters based on the differences and ratios to identify gas-bearing layers. Some researchers have added resistivity to the three-porosity logging method, developing the four-porosity ratio method. Other researchers identify gas-bearing layers by using pairwise cross-plots of calculated relative values ​​of acoustic transit time, relative values ​​of density logging, and relative values ​​of neutron porosity. Some researchers directly use the intersection of neutron porosity and density porosity to identify gas layers, while others use the ratio of acoustic transit time to density. Some researchers have proposed an acoustic transit time difference method to identify gas layers by comparing acoustic transit times with those of water layers.

[0004] Existing methods for identifying gas-bearing reservoirs using the principle of three-porosity curves rely on highlighting the gas response. However, in tight sandstone with high bound water, where gas and water coexist, the water response cannot be ignored, leading to complex three-porosity logging responses. Existing methods for identifying gas-bearing reservoirs using three-porosity curves cannot effectively identify fluids, becoming a bottleneck factor restricting the determination of whether tight reservoirs have economic productivity. This results in low success rates for reservoir fracturing operations or the inability to identify economically productive oil and gas layers. Currently, there is limited research on fluid identification using three-porosity curve analysis of the water response in tight sandstone. For tight sandstone with high bound water, effective fluid identification is closely related to whether the reservoir possesses economic productivity. Summary of the Invention

[0005] To address the problems in the prior art, this application proposes a method, apparatus, device, and storage medium for identifying fluids in dense sandstone with high bound water, thereby solving the problem of ineffective identification of fluids in dense sandstone with high bound water.

[0006] This invention provides a method for identifying fluids in dense sandstone with high bound water, the method comprising:

[0007] Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data;

[0008] The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0009] The above-mentioned method for fluid identification in dense sandstone with high bound water further includes a method for drawing a fluid identification chart formed by water-bearing indicator parameters and gas-bearing indicator parameters, comprising:

[0010] The tested high-bound water tight sandstone was divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum were obtained.

[0011] Calculate the water-bearing indicator parameters and gas-bearing indicator parameters for each of the aforementioned strata;

[0012] Plot the cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned strata, and analyze the sensitivity of the water-bearing indicator parameters of the strata to water response;

[0013] Plot the gas-bearing indicator parameters and unobstructed flow rate cross plots for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response.

[0014] Draw fluid identification charts for each of the aforementioned strata, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

[0015] The above-mentioned method for identifying fluids in dense sandstone with high bound water further includes multiple different types of strata, such as gas layers, gas-water co-layers, differential gas layers, and dry layers.

[0016] The aforementioned method for identifying fluids in high-bound-water tight sandstone further includes, in part, the calculation of water-bearing and gas-bearing indicators of the target formation based on well logging data, the following additional steps:

[0017] Acquire acoustic porosity, compensated neutron, and deep lateral resistivity of the target formation;

[0018] The water content indication parameters of the target formation are calculated based on the acoustic porosity and the compensated neutron.

[0019] The gas-bearing indicator parameters of the target formation are calculated based on the acoustic porosity and the deep lateral resistivity.

[0020] The aforementioned method for identifying fluids in high-bound-water tight sandstone further includes, in part, the calculation of water-bearing indication parameters of the target formation based on the acoustic porosity and the compensated neutron, comprising:

[0021] Calculate the porosity difference of the target formation based on the acoustic porosity and the compensated neutron;

[0022] The water content indicator parameters of the target formation are calculated based on the porosity difference and the compensated neutron.

[0023] The above-mentioned method for identifying fluids in dense sandstone with high bound water further includes the following formula for calculating the porosity difference:

[0024] DPAN = PAC-CNL

[0025] The formula for calculating the water content indicator parameter is as follows:

[0026] IW = a * DPAN * CNL

[0027] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0028] The above-mentioned method for identifying fluids in dense sandstone with high bound water further includes the following formula for calculating the gas-bearing indicator parameter:

[0029] IG = c * LLD * PAC b

[0030] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0031] The present invention also provides a fluid identification device for dense sandstone with high bound water, characterized in that it comprises:

[0032] The calculation module is used to calculate the water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on well logging data;

[0033] The determination module is used to compare the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters to determine the formation type of the target formation.

[0034] The present invention also provides a fluid identification device for dense sandstone with high bound water, including a memory and a processor;

[0035] The memory stores a computer program that, when executed by a processor, implements the steps of the fluid identification method for high-bound water tight sandstone as described above.

[0036] The present invention also provides a storage medium storing a computer program thereon, characterized in that, when the computer program is executed by a processor, it implements the steps of the fluid identification method for high-bound water tight sandstone as described in any of the preceding claims.

[0037] The above-mentioned technical features can be combined in various suitable ways or replaced by equivalent technical features, as long as the purpose of the present invention can be achieved.

[0038] This invention provides a method, apparatus, device, and storage medium for fluid identification in high-bound-water tight sandstone. Compared with existing technologies, it offers at least the following advantages: It calculates water-bearing and gas-bearing indicator parameters for the target formation based on well logging data; it compares these parameters with a fluid identification chart formed from the water-bearing and gas-bearing indicators to determine the formation type of the target formation. By using these parameters to determine the type of the target formation, the fluid type identification result corresponding to the target formation is obtained. Compared to existing three-porosity curve identification methods that emphasize gas response to identify gas layers, this invention adds an identification index for water response in high-bound-water tight sandstone, more effectively identifying fluids and thus determining whether high-bound-water tight sandstone reservoirs have economic productivity, improving the success rate of reservoir fracturing operations or accurately identifying economically productive oil and gas layers.

[0039] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0040] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0041] The invention will now be described in more detail with reference to embodiments and the accompanying drawings.

[0042] Figure 1 The diagram shows a flow chart of a method for identifying fluids in dense sandstone with high bound water according to an embodiment of the present invention.

[0043] Figure 2 Showing Figure 1 A flowchart illustrating the method for drawing a fluid identification chart formed by water content indicator parameters and gas content indicator parameters;

[0044] Figure 3 Showing Figure 1 A flowchart illustrating step S10;

[0045] Figure 4 The diagram shows a cross-plot of daily water production and water content indication parameter (IW) for a single-layer test according to an embodiment of the present invention.

[0046] Figure 5 The diagram shows a cross-plot of the single-layer test flow rate without obstruction and the gas-indicating parameter (IG) according to an embodiment of the present invention.

[0047] Figure 6 This invention illustrates a fluid identification chart formed by water content indicator parameters (IW) and gas content indicator parameters (IG) according to an embodiment of the invention.

[0048] Figure 7 A schematic diagram of the structure of a fluid identification device for dense sandstone with high bound water according to an embodiment of the present invention is shown.

[0049] In the accompanying drawings, the same parts use the same reference numerals. The drawings are not to scale. Detailed Implementation

[0050] Embodiments of the present invention are described in detail below. Examples of these embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals denote the same or similar elements or elements having the same or similar functions throughout. The embodiments described below with reference to the accompanying drawings are exemplary and are only used to explain the present invention, and should not be construed as limiting the present invention.

[0051] In the description of this invention, it should be understood that the terms "center," "longitudinal," "lateral," "length," "width," "thickness," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," "outer," "clockwise," "counterclockwise," "axial," "radial," and "circumferential" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0052] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Thus, a feature defined as "first" or "second" may explicitly or implicitly include one or more of that feature. In the description of this invention, "a plurality of" means two or more, unless otherwise explicitly specified.

[0053] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0054] In this invention, unless otherwise explicitly specified and limited, "above" or "below" the second feature can mean that the first feature is in direct contact with the second feature, or that the first feature is in indirect contact with the second feature through an intermediate medium. Furthermore, "above," "over," and "on top" of the second feature can mean that the first feature is directly above or diagonally above the second feature, or simply that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the second feature can mean that the first feature is directly below or diagonally below the second feature, or simply that the first feature is at a lower horizontal level than the second feature.

[0055] The invention will now be further described with reference to the accompanying drawings.

[0056] Example 1

[0057] This invention provides a method for identifying fluids in dense sandstone with high bound water, in order to solve the problem that fluids in dense sandstone with high bound water cannot be effectively identified.

[0058] Figure 1 This is a schematic flowchart of a method for identifying fluids in dense sandstone with high bound water, provided in an embodiment of the present invention.

[0059] like Figure 1 As shown, the fluid identification method for high-bound water tight sandstone provided in this embodiment of the invention includes the following steps:

[0060] S10: Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data.

[0061] The water-bearing and gas-bearing indicators of the target formation are calculated based on the acoustic porosity, compensated neutrons, and deep lateral resistivity of the target formation.

[0062] S20: The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with the fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0063] By comparing the fluid identification charts formed by water-bearing and gas-bearing indicator parameters of each stratum, the stratum type corresponding to the target stratum can be determined.

[0064] Existing methods for identifying gas-bearing formations using the principle of three-porosity curves rely on prominent gas responses. However, in high-bound-water tight sandstone, where gas and water coexist, the water response is significant, complicating the three-porosity logging response. Existing methods cannot effectively identify fluids, becoming a bottleneck in determining whether tight reservoirs possess sweet spots, leading to low success rates in reservoir fracturing operations or failure to identify economically productive oil and gas layers. In contrast, the fluid identification method for high-bound-water tight sandstone provided in this invention identifies water-bearing formations in the high-bound-water tight sandstone using water-bearing indicator parameters (i.e., prominent water responses) and gas-bearing indicator parameters (i.e., prominent gas responses) of each formation. Simultaneously, the water-bearing and gas-bearing indicator parameters of each formation are analyzed to identify fluids in the high-bound-water tight sandstone. For tight sandstone with high bound water, where gas and water coexist in the formation, the fluid identification method for tight sandstone with high bound water provided in this embodiment of the invention simultaneously analyzes the water-bearing indicator parameters and gas-bearing indicator parameters of each formation, which increases the success rate of reservoir fracturing operations or enables the identification of oil and gas layers with economic production capacity.

[0065] The fluid identification method for high-bound-water tight sandstone provided in this invention calculates water-bearing and gas-bearing indicator parameters of the target formation based on well logging data. These parameters are then compared with a fluid identification chart formed by the water-bearing and gas-bearing indicator parameters to determine the formation type of the target formation. By using these parameters to determine the type of the target formation, the corresponding fluid type identification result is obtained. Compared to existing three-porosity curve identification methods that emphasize gas response to identify gas layers, this method adds an identification index for water response in high-bound-water tight sandstone, more effectively identifying fluids and thus determining whether the high-bound-water tight sandstone reservoir has economic productivity, improving the success rate of reservoir fracturing operations or accurately identifying economically productive oil and gas layers.

[0066] Example 2

[0067] This invention provides a method for identifying fluids in dense sandstone with high bound water, in order to solve the problem that fluids in dense sandstone with high bound water cannot be effectively identified.

[0068] The fluid identification method for high-bound water tight sandstone provided in this embodiment of the invention includes the following steps for drawing a fluid identification chart formed by water-bearing indicator parameters and gas-bearing indicator parameters:

[0069] S10: Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data.

[0070] The water-bearing and gas-bearing indicators of the target formation are calculated based on the acoustic porosity, compensated neutrons, and deep lateral resistivity of the target formation.

[0071] S20: The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with the fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0072] By comparing the fluid identification charts formed by water-bearing and gas-bearing indicator parameters of each stratum, the stratigraphic type corresponding to the target stratum can be determined.

[0073] Please see Figure 2 The method for drawing a fluid identification chart formed by water content indicator parameters and gas content indicator parameters includes the following steps:

[0074] S21: The tested high-bound water tight sandstone is divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum are obtained.

[0075] Referring to the natural gas industry standard testing specifications and combining reservoir engineering and geology expertise, the economic limits for gas production, dry zone limits, and gas production ratio standards for vertical well testing were determined. Formations meeting the economic gas production and gas production ratio standards were defined as gas zones; formations meeting the economic gas production but not the gas production ratio standards were defined as gas-water co-containment zones; formations not meeting the economic gas production but exceeding the dry zone limit and meeting the gas production ratio standards were defined as poor gas zones; and formations with daily liquid production below the dry zone limit were defined as dry zones. Acoustic porosity (PAC), compensated neutron density (CNL), and deep lateral resistivity (LLD) were measured in high-bound-water tight sandstone formations.

[0076] S22: Calculate the water-bearing indicator parameters and gas-bearing indicator parameters of each of the aforementioned formations.

[0077] Calculate the water content indication parameters for each of the formations based on the acoustic porosity and the compensated neutrons:

[0078] Calculate the porosity difference of each formation, porosity difference = acoustic porosity - compensated neutron.

[0079] That is: DPAN = PAC - CNL;

[0080] Calculate the water-bearing indicator parameters for each of the aforementioned formations. Water-bearing indicator parameter = a * porosity difference * compensated neutron.

[0081] That is: IW = a * DPAN * CNL;

[0082] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0083] Calculate the gas-bearing indicator parameters for each formation based on the acoustic porosity and the deep lateral resistivity:

[0084] The formula for calculating the gas content indicator parameter is: Gas content indicator parameter = c * deep lateral resistivity * acoustic porosity b ;

[0085] That is: IG = c * LLD * PAC b ;

[0086] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0087] S23: Draw a cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned formations, and analyze the sensitivity of the water-bearing indicator parameters of the formations to water response.

[0088] Draw cross-plots of water content indicators and daily water production for gas-bearing, gas-water co-layers, differential gas-bearing, and dry layers in high-bound-water tight sandstone. Use water content indicators to distinguish between gas-bearing, gas-water co-layers, differential gas-bearing, and dry layers in high-bound-water tight sandstone.

[0089] When dense sandstone with high bound water contains water, the compensated neutron (CNL) value is high. When the formation water saturation is high, the depth porosity difference (DPAN) value is low. The addition of the compensated neutron (CNL) parameter further enhances the sensitivity to formation water saturation response. The higher the water saturation, the smaller the DPAN, the higher the CNL, and the smaller the water indicator parameter (IW) value.

[0090] S24: Draw cross plots of gas-bearing indicator parameters and unobstructed flow rates for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response.

[0091] Draw cross-plots of gas-bearing indicators and unobstructed flow rates for gas-bearing layers, gas-water co-layers, gas-differential layers, and dry layers in high-bound-water tight sandstone. Use the gas-bearing indicators to distinguish between gas-bearing layers, gas-water co-layers, gas-differential layers, and dry layers in high-bound-water tight sandstone.

[0092] When dense sandstone with high bound water contains gas, the acoustic transit time increases, making it sensitive to gas-bearing responses. Deep lateral measurement operates on a series principle and is sensitive to high resistivity; therefore, for dense sandstone with high bound water, deep lateral measurement is more effective in detecting reservoir gas content. The combination of acoustic porosity (PAC) and deep lateral resistivity (LLD) further enhances the sensitivity to formation gas-bearing responses. Higher gas saturation results in a larger gas-bearing indicator parameter (IG) value.

[0093] S25: Draw fluid identification charts for each of the aforementioned formations, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

[0094] Existing methods for identifying gas-bearing formations using the principle of three-porosity curves rely on prominent gas responses. However, in high-bound-water tight sandstone, where gas and water coexist, the water response is significant, complicating the three-porosity logging response. Existing methods cannot effectively identify fluids, becoming a bottleneck in determining whether tight reservoirs have sweet spots, leading to low success rates in reservoir fracturing or failure to identify economically viable oil and gas layers. In contrast, the fluid identification method for high-bound-water tight sandstone provided in this invention identifies water-bearing formations by using water-bearing indicator parameters (i.e., prominent water responses) and gas-bearing indicator parameters (i.e., prominent gas responses) to identify gas-bearing formations. Simultaneously, the water-bearing and gas-bearing indicator parameters of each formation are analyzed to identify fluids within the high-bound-water tight sandstone. For tight sandstone with high bound water, where gas and water coexist in the formation, the fluid identification method for tight sandstone with high bound water provided in this embodiment of the invention simultaneously analyzes the water-bearing indicator parameters and gas-bearing indicator parameters of each formation, which increases the success rate of reservoir fracturing operations or enables the identification of oil and gas layers with economic production capacity.

[0095] The fluid identification method for high-bound-water tight sandstone provided in this invention calculates water-bearing and gas-bearing indicator parameters of the target formation based on well logging data. These parameters are then compared with a fluid identification chart formed by the water-bearing and gas-bearing indicator parameters to determine the formation type of the target formation. By using these parameters to determine the type of the target formation, the corresponding fluid type identification result is obtained. Compared to existing three-porosity curve identification methods that emphasize gas response to identify gas layers, this method adds an identification index for water response in high-bound-water tight sandstone, more effectively identifying fluids and thus determining whether the high-bound-water tight sandstone reservoir has economic productivity, improving the success rate of reservoir fracturing operations or accurately identifying economically productive oil and gas layers.

[0096] Example 3

[0097] This invention provides a method for identifying fluids in dense sandstone with high bound water, in order to solve the problem that fluids in dense sandstone with high bound water cannot be effectively identified.

[0098] Figure 1 This is a schematic flowchart of a method for identifying fluids in dense sandstone with high bound water, provided in an embodiment of the present invention.

[0099] like Figure 1As shown, the fluid identification method for high-bound water tight sandstone provided in this embodiment of the invention includes the following steps:

[0100] S10: Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data.

[0101] The water-bearing and gas-bearing indicators of the target formation are calculated based on the acoustic porosity, compensated neutron density, and deep lateral resistivity. Please refer to [link / reference needed]. Figure 3 Step S10: Calculate the water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on the well logging data, including:

[0102] S11: Obtain the acoustic porosity, compensated neutron, and deep lateral resistivity of the target formation.

[0103] Acoustic porosity (PAC), compensated neutron (CNL), and deep lateral resistivity (LLD) of high-bound water dense sandstone were measured.

[0104] S12: Calculate the water content indicator parameters of the target formation based on the acoustic porosity and the compensated neutron.

[0105] Calculate the porosity difference of the target formation. Porosity difference = acoustic porosity - compensated neutrons.

[0106] That is: DPAN = PAC - CNL;

[0107] Calculate the water-bearing indicator parameters of the target formation. Water-bearing indicator parameter = a * porosity difference * compensated neutron.

[0108] That is: IW = a * DPAN * CNL;

[0109] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0110] S13: Calculate the gas-bearing indicator parameters of the target formation based on the acoustic porosity and the deep lateral resistivity.

[0111] The formula for calculating the gas content indicator parameter is: Gas content indicator parameter = c * deep lateral resistivity * acoustic porosity b ;

[0112] That is: IG = c * LLD * PAC b ;

[0113] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0114] S20: The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with the fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0115] By comparing the fluid identification charts formed by water-bearing and gas-bearing indicator parameters of each stratum, the stratigraphic type corresponding to the target stratum can be determined.

[0116] Please see Figure 2 The method for drawing a fluid identification chart formed by water content indicator parameters and gas content indicator parameters includes the following steps:

[0117] S21: The tested high-bound water tight sandstone is divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum are obtained.

[0118] Referring to the natural gas industry standard testing specifications and combining reservoir engineering and geology expertise, the economic limits for gas production, dry zone limits, and gas production ratio standards for vertical well testing were determined. Formations meeting the economic gas production and gas production ratio standards were defined as gas zones; formations meeting the economic gas production but not the gas production ratio standards were defined as gas-water co-containment zones; formations not meeting the economic gas production but exceeding the dry zone limit and meeting the gas production ratio standards were defined as poor gas zones; and formations with daily liquid production below the dry zone limit were defined as dry zones. Acoustic porosity (PAC), compensated neutron density (CNL), and deep lateral resistivity (LLD) were measured in high-bound-water tight sandstone formations.

[0119] S22: Calculate the water-bearing indicator parameters and gas-bearing indicator parameters of each of the aforementioned formations.

[0120] Calculate the water content indication parameters for each of the formations based on the acoustic porosity and the compensated neutrons:

[0121] Calculate the porosity difference of each formation, porosity difference = acoustic porosity - compensated neutron.

[0122] That is: DPAN = PAC - CNL;

[0123] Calculate the water-bearing indicator parameters for each of the aforementioned formations. Water-bearing indicator parameter = a * porosity difference * compensated neutron.

[0124] That is: IW = a * DPAN * CNL;

[0125] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0126] Calculate the gas-bearing indicator parameters for each formation based on the acoustic porosity and the deep lateral resistivity:

[0127] The formula for calculating the gas content indicator parameter is: Gas content indicator parameter = c * deep lateral resistivity * acoustic porosity b ;

[0128] That is: IG = c * LLD * PAC b ;

[0129] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0130] S23: Draw a cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned formations, and analyze the sensitivity of the water-bearing indicator parameters of the formations to water response.

[0131] Draw cross-plots of water content indicators and daily water production for gas-bearing, gas-water co-layers, differential gas-bearing, and dry layers in high-bound-water tight sandstone. Use water content indicators to distinguish between gas-bearing, gas-water co-layers, differential gas-bearing, and dry layers in high-bound-water tight sandstone.

[0132] When dense sandstone with high bound water contains water, the compensated neutron (CNL) value is high. When the formation water saturation is high, the depth porosity difference (DPAN) value is low. The addition of the compensated neutron (CNL) parameter further enhances the sensitivity to formation water saturation response. The higher the water saturation, the smaller the DPAN, the higher the CNL, and the smaller the water indicator parameter (IW) value.

[0133] S24: Draw cross plots of gas-bearing indicator parameters and unobstructed flow rates for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response.

[0134] Draw cross-plots of gas-bearing indicators and unobstructed flow rates for gas-bearing layers, gas-water co-layers, gas-differential layers, and dry layers in high-bound-water tight sandstone. Use the gas-bearing indicators to distinguish between gas-bearing layers, gas-water co-layers, gas-differential layers, and dry layers in high-bound-water tight sandstone.

[0135] When dense sandstone with high bound water contains gas, the acoustic transit time increases, making it sensitive to gas-bearing responses. Deep lateral measurement operates on a series principle and is sensitive to high resistivity; therefore, for dense sandstone with high bound water, deep lateral measurement is more effective in detecting reservoir gas content. The combination of acoustic porosity (PAC) and deep lateral resistivity (LLD) further enhances the sensitivity to formation gas-bearing responses. Higher gas saturation results in a larger gas-bearing indicator parameter (IG) value.

[0136] S25: Draw fluid identification charts for each of the aforementioned formations, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

[0137] Existing methods for identifying gas-bearing formations using the principle of three-porosity curves rely on prominent gas responses. However, in high-bound-water tight sandstone, where gas and water coexist, the water response is significant, complicating the three-porosity logging response. Existing methods cannot effectively identify fluids, becoming a bottleneck in determining whether tight reservoirs possess sweet spots, leading to low success rates in reservoir fracturing operations or failure to identify economically productive oil and gas layers. In contrast, the fluid identification method for high-bound-water tight sandstone provided in this invention identifies water-bearing formations in the high-bound-water tight sandstone using water-bearing indicator parameters (i.e., prominent water responses) and gas-bearing indicator parameters (i.e., prominent gas responses) of each formation. Simultaneously, the water-bearing and gas-bearing indicator parameters of each formation are analyzed to identify fluids in the high-bound-water tight sandstone. For tight sandstone with high bound water, where gas and water coexist in the formation, the fluid identification method for tight sandstone with high bound water provided in this embodiment of the invention simultaneously analyzes the water-bearing indicator parameters and gas-bearing indicator parameters of each formation, which increases the success rate of reservoir fracturing operations or enables the identification of oil and gas layers with economic production capacity.

[0138] The fluid identification method for high-bound-water tight sandstone provided in this invention calculates water-bearing and gas-bearing indicator parameters of the target formation based on well logging data. These parameters are then compared with a fluid identification chart formed by the water-bearing and gas-bearing indicator parameters to determine the formation type of the target formation. By using these parameters to determine the type of the target formation, the corresponding fluid type identification result is obtained. Compared to existing three-porosity curve identification methods that emphasize gas response to identify gas layers, this method adds an identification index for water response in high-bound-water tight sandstone, more effectively identifying fluids and thus determining whether the high-bound-water tight sandstone reservoir has economic productivity, improving the success rate of reservoir fracturing operations or accurately identifying economically productive oil and gas layers.

[0139] Example 4

[0140] This invention provides a method for identifying fluids in dense sandstone with high bound water, in order to solve the problem that fluids in dense sandstone with high bound water cannot be effectively identified.

[0141] This embodiment takes the stratigraphic identification of the He 1 section of the Xinzhaoqi area in the Ordos Basin as an example to further explain the fluid identification method for high-bound water tight sandstone provided by this invention.

[0142] The fluid identification method for high-bound water tight sandstone provided in this embodiment of the invention includes the following steps:

[0143] S10: Calculate the water-bearing and gas-bearing indicators of the He 1 formation in the Xinzhao gas-bearing area of ​​the Ordos Basin based on well logging data.

[0144] The water-bearing and gas-bearing indicators of the target formation are calculated based on the acoustic porosity, compensated neutrons, and deep lateral resistivity of the target formation.

[0145] S11: Obtain acoustic porosity, compensated neutron, and deep lateral resistivity of the He 1 formation in the Xinzhao gas area of ​​the Ordos Basin.

[0146] Acoustic porosity (PAC), compensated neutron (CNL), and deep lateral resistivity (LLD) of high-bound water dense sandstone were measured.

[0147] S12: Calculate the water content indicator parameters of the He 1 section strata in the Xinzhao gas area of ​​the Ordos Basin based on the acoustic porosity and the compensated neutron.

[0148] Calculate the porosity difference of the target formation. Porosity difference = acoustic porosity - compensated neutrons.

[0149] That is: DPAN = PAC - CNL;

[0150] Calculate the water-bearing indicator parameters of the target formation. Water-bearing indicator parameter = a * porosity difference * compensated neutron.

[0151] That is: IW = a * DPAN * CNL;

[0152] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0153] S13: Calculate the gas-bearing indicator parameters of the He 1 section strata in the Xinzhao gas-bearing area of ​​the Ordos Basin based on the acoustic porosity and the deep lateral resistivity.

[0154] The formula for calculating the gas content indicator parameter is: Gas content indicator parameter = c * deep lateral resistivity * acoustic porosity b ;

[0155] That is: IG = c * LLD * PAC b ;

[0156] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0157] S20: The stratigraphic type of the He 1 section of the Xinzhao gas area in the Ordos Basin is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with the fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0158] Please see Figure 2 The method for drawing a fluid identification chart formed by water content indicator parameters and gas content indicator parameters includes the following steps:

[0159] S21: The tested high-bound water tight sandstone is divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum are obtained.

[0160] Referring to the natural gas industry standard testing specifications and combining reservoir engineering and geology expertise, the economic limits for gas production, dry zone limits, and gas production ratio standards for vertical well testing were determined. Formations meeting the economic gas production and gas production ratio standards were defined as gas zones; formations meeting the economic gas production but not the gas production ratio standards were defined as gas-water co-containment zones; formations not meeting the economic gas production but exceeding the dry zone limit and meeting the gas production ratio standards were defined as poor gas zones; and formations with daily liquid production below the dry zone limit were defined as dry zones. Acoustic porosity (PAC), compensated neutron density (CNL), and deep lateral resistivity (LLD) were measured in high-bound-water tight sandstone formations.

[0161] S22: Calculate the water-bearing indicator parameters and gas-bearing indicator parameters of each of the aforementioned formations.

[0162] Calculate the water content indication parameters for each of the formations based on the acoustic porosity and the compensated neutrons:

[0163] Calculate the porosity difference of each formation, porosity difference = acoustic porosity - compensated neutron.

[0164] That is: DPAN = PAC - CNL;

[0165] Calculate the water-bearing indicator parameters for each of the aforementioned formations. Water-bearing indicator parameter = a * porosity difference * compensated neutron.

[0166] That is: IW = a * DPAN * CNL;

[0167] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0168] Calculate the gas-bearing indicator parameters for each formation based on the acoustic porosity and the deep lateral resistivity:

[0169] The formula for calculating the gas content indicator parameter is: Gas content indicator parameter = c * deep lateral resistivity * acoustic porosity b ;

[0170] That is: IG = c * LLD * PAC b ;

[0171] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0172] S23: Draw a cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned formations, and analyze the sensitivity of the water-bearing indicator parameters of the formations to water response.

[0173] Please see Figure 4 A cross-plot of water content indicators and daily water production was plotted for gas-bearing, gas-water co-layers, differential gas-bearing, and dry layers in high-bound-water tight sandstone. The water content indicators were used to distinguish between gas-bearing, gas-water co-layers, differential gas-bearing, and dry layers in high-bound-water tight sandstone.

[0174] When dense sandstone with high bound water contains water, the compensated neutron (CNL) value is high. When the formation water saturation is high, the depth porosity difference (DPAN) value is low. The addition of the compensated neutron (CNL) parameter further enhances the sensitivity to formation water saturation response. The higher the water saturation, the smaller the DPAN, the higher the CNL, and the smaller the water indicator parameter (IW) value.

[0175] S24: Draw cross plots of gas-bearing indicator parameters and unobstructed flow rates for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response.

[0176] Please see Figure 5 The gas-bearing indicator parameters and unobstructed flow cross-plots of gas-bearing layers, gas-water co-layers, gas-differential layers, and dry layers in high-bound-water tight sandstone were plotted. The gas-bearing indicator parameters were used to distinguish between gas-bearing layers, gas-water co-layers, gas-differential layers, and dry layers in high-bound-water tight sandstone.

[0177] When dense sandstone with high bound water contains gas, the acoustic transit time increases, making it sensitive to gas-bearing responses. Deep lateral measurement operates on a series principle and is sensitive to high resistivity; therefore, for dense sandstone with high bound water, deep lateral measurement is more effective in detecting reservoir gas content. The combination of acoustic porosity (PAC) and deep lateral resistivity (LLD) further enhances the sensitivity to formation gas-bearing responses. Higher gas saturation results in a larger gas-bearing indicator parameter (IG) value.

[0178] S25: Draw fluid identification charts for each of the aforementioned formations, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

[0179] Figure 6 This is a fluid identification chart formed by water content indicator (IW) and gas content indicator (IG) in an embodiment of the present invention. As shown in the figure, by combining the water content indicator (IW) and gas content indicator (IG), the gas layer, differential gas layer, gas-water co-layer, and dry layer in the He 1 section of the Xinzhao gas field in the Ordos Basin can be effectively distinguished, with an accuracy rate of over 90%.

[0180] The specific identification criteria are shown in Table 1.

[0181] Table 1

[0182]

[0183] By comparing the fluid identification charts formed by water-bearing and gas-bearing indicator parameters of each stratum, the stratigraphic type corresponding to the He 1 section of the Xinzhao gas area in the Ordos Basin can be determined.

[0184] The fluid identification method for high-bound-water tight sandstone provided in this invention divides the high-bound-water tight sandstone into multiple different types of strata; draws fluid identification maps for each stratum using water-bearing and gas-bearing indicator parameters; calculates the water-bearing and gas-bearing indicator parameters of the target stratum; and determines the type of the target stratum based on the fluid identification maps formed by the water-bearing and gas-bearing indicator parameters. By using the water-bearing and gas-bearing indicator parameters to determine the type of the target stratum, the fluid type identification result corresponding to the target stratum is obtained. Compared with the existing three-porosity curve identification method, which emphasizes gas response to identify gas layers, this method adds an identification index for water response in high-bound-water tight sandstone, more effectively identifying fluids, thereby determining whether the high-bound-water tight sandstone reservoir has economic productivity, improving the success rate of reservoir fracturing operations, or accurately identifying oil and gas layers with economic productivity.

[0185] Example 5

[0186] This invention provides a device for identifying fluids in dense sandstone with high bound water, in order to solve the problem of ineffective identification of fluids in dense sandstone with high bound water.

[0187] Figure 7 A schematic diagram of the structure of a fluid identification device for high-bound water dense sandstone according to an embodiment of the present invention is shown, as follows: Figure 7 As shown, the fluid identification device for high-bound water dense sandstone in this embodiment includes a calculation module 71 and a determination module 72.

[0188] The calculation module 71 is used to calculate the water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on the well logging data.

[0189] The water-bearing and gas-bearing indicators of the target formation are calculated based on the acoustic porosity, compensated neutrons, and deep lateral resistivity of the target formation.

[0190] The determination module 72 is used to compare the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters to determine the formation type of the target formation.

[0191] By comparing the fluid identification charts formed by water-bearing and gas-bearing indicator parameters of each stratum, the stratigraphic type corresponding to the target stratum can be determined.

[0192] Existing methods for identifying gas-bearing formations using the principle of three-porosity curves rely on prominent gas responses. However, in high-bound-water tight sandstone, where gas and water coexist, the water response is significant, complicating the three-porosity logging response. Existing methods cannot effectively identify fluids, becoming a bottleneck in determining whether tight reservoirs possess sweet spots, leading to low success rates in reservoir fracturing operations or failure to identify economically productive oil and gas layers. In contrast, the fluid identification method for high-bound-water tight sandstone provided in this invention identifies water-bearing formations in the high-bound-water tight sandstone using water-bearing indicator parameters (i.e., prominent water responses) and gas-bearing indicator parameters (i.e., prominent gas responses) of each formation. Simultaneously, the water-bearing and gas-bearing indicator parameters of each formation are analyzed to identify fluids in the high-bound-water tight sandstone. For tight sandstone with high bound water, where gas and water coexist in the formation, the fluid identification method for tight sandstone with high bound water provided in this embodiment of the invention simultaneously analyzes the water-bearing indicator parameters and gas-bearing indicator parameters of each formation, which increases the success rate of reservoir fracturing operations or enables the identification of oil and gas layers with economic production capacity.

[0193] The fluid identification method for high-bound-water tight sandstone provided in this invention calculates water-bearing and gas-bearing indicator parameters of the target formation based on well logging data. These parameters are then compared with a fluid identification chart formed by the water-bearing and gas-bearing indicator parameters to determine the formation type of the target formation. By using these parameters to determine the type of the target formation, the corresponding fluid type identification result is obtained. Compared to existing three-porosity curve identification methods that emphasize gas response to identify gas layers, this method adds an identification index for water response in high-bound-water tight sandstone, more effectively identifying fluids and thus determining whether the high-bound-water tight sandstone reservoir has economic productivity, improving the success rate of reservoir fracturing operations or accurately identifying economically productive oil and gas layers.

[0194] It should be noted that the apparatus in the above embodiments is used to implement the corresponding methods in the foregoing embodiments and has the beneficial effects of the corresponding method embodiments, which will not be repeated here.

[0195] Example 6

[0196] This invention provides a fluid identification device for dense sandstone with high bound water, in order to solve the problem that fluids in dense sandstone with high bound water cannot be effectively identified.

[0197] The fluid identification device for dense sandstone with high bound water provided in this embodiment of the invention includes a memory and a processor.

[0198] The memory stores a computer program that, when executed by a processor, implements the steps of a method for identifying fluids in dense sandstone with high bound water.

[0199] Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data;

[0200] The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0201] The fluid identification device for high-bound water tight sandstone provided in this embodiment of the invention further includes a method for drawing the fluid identification map formed by water-bearing indicator parameters and gas-bearing indicator parameters, comprising:

[0202] The tested high-bound water tight sandstone was divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum were obtained.

[0203] Calculate the water-bearing indicator parameters and gas-bearing indicator parameters for each of the aforementioned strata;

[0204] Plot the cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned strata, and analyze the sensitivity of the water-bearing indicator parameters of the strata to water response;

[0205] Plot the gas-bearing indicator parameters and unobstructed flow rate cross plots for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response.

[0206] Draw fluid identification charts for each of the aforementioned strata, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

[0207] The fluid identification device for high-bound water tight sandstone provided in this embodiment of the invention further includes multiple different types of strata, including gas layers, gas-water co-layers, differential gas layers, and dry layers.

[0208] The fluid identification device for high-bound water tight sandstone provided in this embodiment of the invention further includes, in addition to, the calculation of water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on well logging data, the following:

[0209] Acquire acoustic porosity, compensated neutron, and deep lateral resistivity of the target formation;

[0210] The water content indication parameters of the target formation are calculated based on the acoustic porosity and the compensated neutron.

[0211] The gas-bearing indicator parameters of the target formation are calculated based on the acoustic porosity and the deep lateral resistivity.

[0212] The fluid identification device for high-bound water tight sandstone provided in this embodiment of the invention further includes, in part, the calculation of water-bearing indication parameters of the target formation based on the acoustic porosity and the compensated neutron, comprising:

[0213] Calculate the porosity difference of the target formation based on the acoustic porosity and the compensated neutron;

[0214] The water content indicator parameters of the target formation are calculated based on the porosity difference and the compensated neutron.

[0215] The fluid identification device for high-bound water dense sandstone provided in this embodiment of the invention further includes a calculation formula for the porosity difference as follows:

[0216] DPAN = PAC-CNL

[0217] The formula for calculating the water content indicator parameter is as follows:

[0218] IW = a * DPAN * CNL

[0219] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0220] The fluid identification device for high-bound water tight sandstone provided in this embodiment of the invention further includes a calculation formula for the gas content indicator parameter as follows:

[0221] IG = c * LLD * PAC b

[0222] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0223] Example 7

[0224] This invention provides a storage medium to address the problem of ineffective identification of fluids in dense sandstone with high bound water.

[0225] The storage medium provided in this embodiment of the invention stores a computer program, which, when executed by a processor, implements the steps of the following method for identifying fluids in dense sandstone with high bound water.

[0226] Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data;

[0227] The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters.

[0228] The storage medium provided in this embodiment of the invention further includes a method for drawing a fluid identification map formed by water content indicator parameters and gas content indicator parameters, comprising:

[0229] The tested high-bound water tight sandstone was divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum were obtained.

[0230] Calculate the water-bearing indicator parameters and gas-bearing indicator parameters for each of the aforementioned strata;

[0231] Plot the cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned strata, and analyze the sensitivity of the water-bearing indicator parameters of the strata to water response;

[0232] Plot the gas-bearing indicator parameters and unobstructed flow rate cross plots for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response.

[0233] Draw fluid identification charts for each of the aforementioned strata, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

[0234] The storage medium provided in this embodiment of the invention further includes multiple different types of formations, including gas layers, gas-water co-layers, differential gas layers, and dry layers.

[0235] The storage medium provided in this embodiment of the invention further includes, in addition to, the calculation of water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on well logging data, the following:

[0236] Acquire acoustic porosity, compensated neutron, and deep lateral resistivity of the target formation;

[0237] The water content indication parameters of the target formation are calculated based on the acoustic porosity and the compensated neutron.

[0238] The gas-bearing indicator parameters of the target formation are calculated based on the acoustic porosity and the deep lateral resistivity.

[0239] The storage medium provided in this embodiment of the invention further includes, in part, the calculation of water content indication parameters of the target formation based on the acoustic porosity and the compensated neutrons, comprising:

[0240] Calculate the porosity difference of the target formation based on the acoustic porosity and the compensated neutron;

[0241] The water content indicator parameters of the target formation are calculated based on the porosity difference and the compensated neutron.

[0242] The storage medium provided in this embodiment of the invention further includes a formula for calculating the porosity difference as follows:

[0243] DPAN = PAC-CNL

[0244] The formula for calculating the water content indicator parameter is as follows:

[0245] IW = a * DPAN * CNL

[0246] Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; and CNL is the compensating neutron.

[0247] The storage medium provided in this embodiment of the invention further includes a calculation formula for the gas content indicator parameter as follows:

[0248] IG = c * LLD * PAC b

[0249] Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

[0250] It is understood that the same or similar parts in the above embodiments can be referred to each other, and the contents not described in detail in some embodiments can be referred to the same or similar contents in other embodiments.

[0251] It should be noted that in the description of this invention, the terms "first," "second," etc., are used for descriptive purposes only and should not be construed as indicating or implying relative importance. Furthermore, in the description of this invention, unless otherwise stated, "a plurality of" means at least two.

[0252] Any process or method description in the flowchart or otherwise herein can be understood as representing a module, segment, or portion of code comprising one or more executable instructions for implementing a particular logical function or process, and the scope of the preferred embodiments of the invention includes additional implementations in which functions may be performed not in the order shown or discussed, including substantially simultaneously or in reverse order depending on the functions involved, as will be understood by those skilled in the art to which embodiments of the invention pertain.

[0253] It should be understood that various parts of the present invention can be implemented in hardware, software, firmware, or a combination thereof. In the above embodiments, multiple steps or methods can be implemented in software or firmware stored in memory and executed by a suitable instruction execution system. For example, if implemented in hardware, as in another embodiment, it can be implemented using any one or a combination of the following techniques known in the art: discrete logic circuits having logic gates for implementing logical functions on data signals, application-specific integrated circuits (ASICs) having suitable combinational logic gates, programmable gate arrays (PGAs), field-programmable gate arrays (FPGAs), etc.

[0254] Those skilled in the art will understand that all or part of the steps of the methods in the above embodiments can be implemented by a program instructing related hardware. The program can be stored in a computer-readable storage medium, and when executed, the program includes one or a combination of the steps of the method embodiments.

[0255] Furthermore, the functional units in the various embodiments of the present invention can be integrated into a processing module, or each unit can exist physically separately, or two or more units can be integrated into a module. The integrated module can be implemented in hardware or as a software functional module. If the integrated module is implemented as a software functional module and sold or used as an independent product, it can also be stored in a computer-readable storage medium.

[0256] The storage media mentioned above can be read-only memory, disk, or optical disk, etc.

[0257] In the description of this specification, references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples.

[0258] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of protection of this invention shall still be determined by the scope defined in the appended claims.

[0259] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the present invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0260] While the invention has been described herein with reference to specific embodiments, it should be understood that these embodiments are merely examples of the principles and applications of the invention. Therefore, it should be understood that many modifications can be made to the exemplary embodiments, and other arrangements can be designed without departing from the spirit and scope of the invention as defined by the appended claims. It should be understood that different dependent claims and features described herein can be combined in ways different from those described in the original claims. It is also understood that features described in conjunction with individual embodiments can be used in other described embodiments.

Claims

1. A method for identifying fluids in dense sandstone with high bound water, characterized in that, The method for identifying fluids in dense sandstone with highly bound water includes: Calculate the water-bearing and gas-bearing indicators of the target formation based on well logging data; The formation type of the target formation is determined by comparing the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters. The calculation of water-bearing and gas-bearing indicator parameters of the target formation based on well logging data also includes: Acquire acoustic porosity, compensated neutron, and deep lateral resistivity of the target formation; The water content indication parameters of the target formation are calculated based on the acoustic porosity and the compensated neutron. Calculate the gas-bearing indicator parameters of the target formation based on the acoustic porosity and the deep lateral resistivity; The formula for calculating the porosity difference is: The formula for calculating the water content indicator parameter is as follows: Wherein, DPAN is the porosity difference; PAC is the acoustic porosity; IW is the water content indicator parameter; a is the coefficient; CNL is the compensating neutron; the calculation formula for the gas content indicator parameter is: Wherein, IG is the gas-containing indicator parameter; LLD is the deep lateral resistivity; PAC is the acoustic porosity; and b and c are coefficients.

2. The method for fluid identification in dense sandstone with high bound water according to claim 1, characterized in that, The method for drawing the fluid identification chart formed by the water content indicator parameter and the gas content indicator parameter includes: The tested high-bound water tight sandstone was divided into several different types of strata, and the acoustic porosity, compensated neutron, and deep lateral resistivity of each stratum were obtained. Calculate the water-bearing indicator parameters and gas-bearing indicator parameters for each of the aforementioned strata; Plot the cross-plot of water-bearing indicator parameters and daily water production for each of the aforementioned strata, and analyze the sensitivity of the water-bearing indicator parameters of the strata to water response; Plot the gas-bearing indicator parameters and unobstructed flow rate cross plots for each of the aforementioned formations, and analyze the sensitivity of the gas-bearing indicator parameters of the formations to the gas response; Draw fluid identification charts for each of the aforementioned strata, formed by water-bearing indicator parameters and gas-bearing indicator parameters.

3. The method for fluid identification in dense sandstone with high bound water according to claim 2, characterized in that, The various types of formations include gas layers, gas-water co-layers, gas-differential layers, and dry layers.

4. A fluid identification device for dense sandstone with high bound water, characterized in that, include: The calculation module is used to calculate the water-bearing indicator parameters and gas-bearing indicator parameters of the target formation based on well logging data; The determination module is used to compare the water-bearing indicator parameters and gas-bearing indicator parameters with a fluid identification chart formed by the water-bearing indicator parameters and gas-bearing indicator parameters to determine the stratigraphic type of the target stratum; the fluid identification device is configured to perform the fluid identification method for high-bound water tight sandstone as described in any one of claims 1 to 3.

5. A fluid identification device for dense sandstone with high bound water, characterized in that, Including memory and processor; The memory stores a computer program that, when executed by a processor, implements the steps of the fluid identification method for high-bound water tight sandstone as described in any one of claims 1 to 3.

6. A storage medium, characterized in that, It stores a computer program, characterized in that, when the computer program is executed by a processor, it implements the steps of the fluid identification method for high-bound water tight sandstone as described in any one of claims 1 to 3.

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